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Atlantic Energy Gateway - Resource Development Modelling Study Report

A Study of Potential Savings for the Combined Resource Planning of Atlantic Canadian Utilities

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, biomass/biofuels, and hydro.

The AEG is focused on contributing to identifying greater regional co-operation, benefits, and efficiencies among the various participants in the electricity and clean renewable energy sectors. This particular study was conducted by ABB Technology Ltd. (Ventyx) under the direction of the Resource Development Modelling Committee of the AEG.  It was undertaken at the request of the AEG Steering Committee and has involved collaborative efforts by the Government of Canada, the Atlantic Provinces and the Atlantic region electric utilities. This document is the final report of the AEG - Resource Development Modelling Committee. 

The fundamental hypothesis behind this study is that benefits can be achieved by regional planning of future electric generating resources rather than planning separately as is done today.  Each of the Atlantic utilities currently develops an integrated resource plan (IRP) for its medium- and long-term future generation development. The objective in this study was to model a more integrated view of the  region and determine the economic and environmental benefits compared to the individual provincial models.

Resource development planning identifies the long-term optimization of power system supply, demand and transmission resources to meet projected reliability, environmental and economic targets.  To achieve the study results, an optimization computer simulation tool called Strategist® was used.  NB Power, NS Power and NL Hydro currently utilize Strategist® and had developed a partial Atlantic simulation model to evaluate the Muskrat Falls portion of the Lower Churchill hydro development entering the region, including the transmission links from Labrador to Newfoundland and from Newfoundland to Nova Scotia. By adding PEI and Northern Maine to this existing model plus revised representations of the Hydro Québec and ISO New England markets, a more detailed expansion simulation was developed for Atlantic Canada.

Study parameters and assumptions were developed by the Resource Development Modelling Committee with assistance from Ventyx. Commercially sensitive confidential utility data was supplied directly to Ventyx and protected via non-disclosure agreements. Ventyx executed the Strategist® model to recreate the proposed IRPs of the four provincial utilities and then compared the sum of their costs against the costs of operating the combined Atlantic region.  All of the resource development options particular to each utility’s IRP were available in the analysis which included the renewable energy potential for wind, tidal, biomass, and hydro plus nuclear and natural gas options. Several environmental regulations were included as development constraints.  These included: renewable energy standards, SO2 and NOx requirements for each province, CO2 emission reduction to 5 Mte by 2020 in Nova Scotia and the federal requirement for coal-fired power plants to emit CO2 equivalent to a combined cycle natural gas plant or better or retire after a 45-year life. In this study, coal-fired power plant retirement was assumed for New Brunswick but an equivalent cap of 5 Mte by 2030 and 4.5 Mte by 2040 was assumed by Nova Scotia.  While this does not exactly match the profile of the CO2 emission cap of the proposed equivalency agreement between the province of Nova Scotia and the federal government related to the GHG regulations (as these limits were still under negotiation during this study work), this assumption is sufficiently close to give confidence in the results.

The systems were simulated in detail for the study period of 2015 through 2040 with the capital costs of each new generation resource charged at its escalating economic carrying cost.  This approach treated projects of differing lives within the study period on a level playing field and eliminated the need to conduct an end effects analysis beyond 2040.   Analysis was completed to determine Least Cost resource model results for a reasonable forecast of future conditions (Base Case scenario), for a High Natural Gas Price future, for a Low Load future and a scenario with Limited Transmission Expansion between NB and NS.  In each of these cases (except for the Limited Transmission Expansion), expansion of the NB-PEI and NB-NS interconnections was assumed to be increased significantly above current transfer levels and the cost of the assumed transmission expansion is not included in the resource models. In addition to Least Cost model results, several “Plans of Interest” were selected to reflect development strategies that focused on Natural Gas, Nuclear in NB and High Renewable Penetration if these were not part of the Least Cost model. These resulting models were subsequently simulated in greater detail to determine annual energy sources and emission levels. The results of the net present value (NPV) analysis of resources options are provided in Figure 1.

A number of resource options (Lower Churchill project for NL Hydro, Lower Churchill participation for NS Power and Grand Falls Redevelopment and Coleson Cove units 1 and 3 conversion to natural gas) are committed in the provincial base case as part of their IRPs and, as such, their costs and benefits relative to existing resources today are not captured in these model results. 

Figure 1 - NPV Costs of Different Resource Development Plans ($Millions)
Scenarios Sum of Standalone Provincial Systems with Existing Transmission Combined Regional System with Expanded Transmission Combined Regional Limited Transmission
Base Case High Gas Price Low Load Base Case High Gas Price Low Load
Nuclear (least cost) $22,395 $24,228 $17,730 $21,516 $23,199 $17,146 $21,608
Natural Gas $22,453 $24,465 $17,769 $21,624 $23,534 $17,232 $21,710
High Renewable $22,408 $24,475 $17,769 $21,635 $23,541 $17,249 $21,718

In viewing these modeled potential resource results, the reader is cautioned that they are indicative and directional in nature. Simulation of power system expansion over a period of 30 years is an approximate exercise subject to many assumptions. The optimization model results were derived from the assumption set and hold true only to the extent that the assumptions are accurate.  It is important to understand that the results are not the total revenue requirement for the region but only the costs of fuel, optional new generation O&M and capital, and new generator interconnection capital.  There is no consideration of any existing or future costs for in- province distribution and transmission and there is no consideration of capital for existing generation resources. It is generally accepted that these will be common across the Cases and net-out of the comparative analysis.  Finally, the opportunity to achieve NPV benefits resulting from combined regional planning have not been segregated by province.  Opportunities are shown from an Atlantic region perspective only.  

Comparison of the different resource scenarios and development plans provided the following findings:

The Nuclear in NB plan, based on cost assumptions, is the least-cost expansion for the Base Case Scenario and the combined regional resource plan is $879 million less cost than the sum of the separate provincial plans. This resource benefit is sufficient to pay the cost of the transmission expansions estimated at $565 million in 2015 and provide a net benefit to the ratepayers of the region of $314 million.  The primary development components, other than Nuclear in NB in 2038, are 114 MW of wind in NS in 2015, three small hydro projects in NL in 2019, 2021 and 2023, a 250 MW combined cycle gas unit in NS in 2030, a 400 MW combined cycle gas unit in NB in 2032 and a 130 MW combined cycle gas unit in PEI in 2033.  The higher gas price in the High Natural Gas Price scenario makes the nuclear plan even more economic than the Base Case Scenario and the regional plan has an NPV benefit of $1029 million (net benefit of $464 million) compared to the High Gas stand-alone provincial plans. Other than installation of 100 MW of wind in each of NS in 2035 and NL in 2039, this High Gas Scenario has the same combined regional resource expansion plan as the Base Case.

In the Low Load Scenario, the least cost plan is still the nuclear expansion, but with the combined regional resource NPV benefits reduced to $584 million (net benefit of $19 million). The Low Load Scenario development plan is similar to the Base Case except that a 400 MW combined cycle gas unit in NB was deferred from 2032 to 2039.    
 
The Limited Transmission sensitivity reduces transfer capabilities from the Expanded Transmission Cases and increases the NPV cost of supply resources by $92 million compared to the combined regional system Base Case.  The expansion plan is the same as the High Gas plan except that the 100 MW of wind in NL is delayed from 2039 to 2040. The wind in NS and NL occurs because the limited interconnection reduces the opportunity for economy transfers from NB to NS so it is needed to enable NS to operate within its CO2 cap.

The value of any development plan is not just measured in financial differences.  Given the global concerns regarding climate change and associated policies to reduce greenhouse gas (GHG) emissions, the amount of emissions from a particular plan is extremely important.  The Expanded Transmission Base Case has emissions in PEI very low in all years and, other than the years prior to operation of Muskrat Falls, emissions in NL are reduced to near zero.  NB emissions, which were near 9 million tonnes in 2005, reduce to less than 3 million tonnes by 2040 after Belledune is retired and the new, larger nuclear unit replaces Point Lepreau.  NS emissions also reduce from near 10 million tonnes in 2005 to just over 7 million tonnes in 2015, to approximately 4 million tonnes by 2030, and remain near that level for the rest of the period. Overall regional emissions are reduced by 64% from 2005 levels. 

The relative energy mix in a resource development plan is also of interest, not just because of its influence on emissions, but also from the perspective of diversity of fuel source risk and fuel price volatility. Fuel sources of coal and oil are imported and depend on world markets for cost and availability while wind and hydro are local and natural gas is currently an indigenous resource (though subject to international market pricing).  In the Expanded Transmission Base Case, the large increase in hydro by 2020 combined with natural gas and a large nuclear unit after 2030 reduces coal and oil generation from its 49% share in 2005 to only 6% by 2040.

The transmission study has determined that the cost of the two transmission expansions between NB-PEI and NB-NS is $565 million in 2015.  With an Expanded Transmission Base Case resource benefit of $879 million, the transmission can be paid for and still provide $314 million of benefit for regional ratepayers. However, the Limited Transmission Sensitivity suggests a benefit of $787 million.  While this particular Sensitivity assumed no expansion of the existing transmission interties, based on current system operating conditions transmission expenditures will be necessary to maintain the present transfer limits into the future.  Accordingly, the benefit of the Limited Transmission Sensitivity is somewhat inflated.  Regardless, the resource benefits derived in this study are only one component of total benefit of transmission and the other considerations (reliability) need to be analyzed and understood prior to any commitment to expand the interconnections. In short, more detailed transmission analysis work is required and it must be integrated with additional resource analysis in order to determine an optimum expansion plan for the region.

While much of this discussion has been focussed on the benefits derived in the model, important areas for policy consideration which establish the winning conditions for renewables described in the modeling are as follows: 

  • Natural Gas Supply and Infrastructure - This resource modelling study shows increased use of natural gas for electricity generation in all scenarios examined.  Development of a long-term regional plan focused on security of natural gas supply and pipeline infrastructure needs would help ensure that the region could enjoy the forecasted cost and the air emission benefits of natural gas generation.

  • Enhanced Transmission Interties - Transmission transfer capacity within the region promotes the sharing of renewable resources and is an important enabler of regional cooperation.  There are significant transmission expansion decisions to be made in the near- to mid-term. A finding of this resource modelling study is that additional transmission analysis is required by the utilities in order to determine an optimal plan for transmission intertie expansion within the region. 

  • Hydroelectric Power - Hydroelectric generation grows to approximately 45% of the region’s electricity supply by 2040. Hydro provides renewable energy but, equally important, it can supply valuable regulation and load following capacity which is a critical enabler of wind and tidal generation.  Efforts to promote new and protect existing hydro generating resources are important to allow the progress of other renewables in the region. 

View related Atlantic Energy Gateway studies.

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