NB Power's 10-Year Plan - Prepared: September 2017 - Énergie NB Power
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NB Power’s 10-Year Plan Prepared: September 2017
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1Under Section 101 of the Electricity Act, New Brunswick Power Corporation (NB Power) is required to prepare a strategic, financial and capital
investment plan covering the next 10 fiscal years and file such plan with the Energy & Utilities Board (EUB) on an annual basis. This 10-year plan is
for informational purposes but is to be taken into consideration during the review of general rate applications and in assessing NB Power’s
progress and forecasted ability to achieve long-term legislated goals and objectives. The following 10-year plan has been prepared in compliance
with the requirements of the Electricity Act and covers the period of fiscal years 2018/19 to 2027/28
The overarching financial goals of NB Power are to reduce debt and create equity in order to provide the utility with some flexibility to manage
operating and financial risk, to respond to changing markets and technologies, and to better prepare for future investment requirements. These
financial goals are also a legislative obligation as the Electricity Act states that rates charged to customers should be sufficient to permit a just and
reasonable return that will allow NB Power to earn sufficient income in order to achieve a capital structure of at least 20 per cent equity. NB
Power recognizes that improving the financial health of the company also supports the overall well-being of New Brunswick. NB Power believes
that progress towards achieving its financial goals should be made on an annual basis. It is committed to achieving these goals by way of
establishing a culture and philosophy of continuous improvement, managing costs and expenditures, identifying new revenue streams and
implementing an appropriate rate strategy.
One of the largest capital expenditures facing NB Power over the course of this 10-year plan is to address the future of the Mactaquac Hydro
Generating Station (Mactaquac). NB Power has announced its recommendation of a “life achievement” project to maintain Mactaquac to its
original intended lifespan of approximately 2068. The life achievement option meets all safety requirements, has the lowest cost estimate when
compared to other options that were under consideration and allows NB Power to take into account changes in costs, technology, electricity
demand and customer priorities going forward. In the coming years, NB Power will seek appropriate environmental and financial approvals. For
financial planning purposes, this 10-year plan includes the lower end of the range of life achievement estimates for the capital expenditures
associated with NB Power’s recommended option. A sensitivity analysis has been provided to outline how financial results could vary if the least
cost option is not the option ultimately approved.
In October 2016, a motion was introduced by the federal government to support ratification of the Paris Climate Change Accord (Paris Accord)
and in December 2016, the federal government released the Pan-Canadian Framework on Clean Growth and Climate Change. This framework
calls for carbon charges starting in 2018 that would continue to escalate until 2022 to help Canada meet Paris Accord requirements. In early
December 2016, the Province of New Brunswick also issued a new action plan, Transitioning to a Low-Carbon Economy, as part of a made-in-New
Brunswick response to climate change that has recommendations on climate change that will impact NB Power. The implications to the 10-year
plan resulting from current discussions and indications from the federal and provincial governments are still uncertain but will result in increased
costs over the course of the 10-year plan period. A range of estimated increases in fuel and purchased power costs has been calculated based on
the federal government’s proposed carbon tax structure. The potential magnitude of the carbon tax structure’s impact to net earnings and the
levelized change to rate increases required to maintain the same approximate financial position at the end of the 10-year plan period has also
been provided. The estimate is subject to variability but is nonetheless indicative of the potential future implications.
2A summary of the key financial highlights of the 10-year plan is provided in Figure 1 below.
Figure 1: Financial Highlights
Fiscal Year Ending March 31 (in millions $) 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Average Rate Increase 2.0% 2.0% 2.0% 2.0% 2.0% 1.0% 1.0% 1.0% 1.0% 1.0%
Gross Margin 1,034 1,068 1,089 1,119 1,125 1,157 1,138 1,200 1,180 1,212
Net Earnings 62 61 102 110 103 127 111 170 164 155
Return on Equity 11% 10% 15% 14% 11% 12% 10% 13% 11% 10%
Capital Expenditures 343 374 291 322 324 291 315 298 680 630
Net Debt 4,911 4,916 4,813 4,732 4,614 4,439 4,280 4,041 4,215 4,318
% Debt in Capital Structure 89.5% 88.5% 86.7% 84.8% 82.9% 80.4% 78.2% 74.8% 73.4% 72.0%
Potential Carbon Cost Impacts
Estimate for Annual Cost of Carbon (in millions $) 20 - 40 30 - 60 55 - 110 60 - 120 85 - 175 75 - 155 90 - 185 85 - 175 105 - 210 90 - 185
Levelized Rate Change for Carbon (up to) 1 0.0% 1.7% 1.7% 1.7% 1.7% 2.7% 2.7% 2.7% 2.7% 2.7%
Total Rate Impact2 2.0% 3.7% 3.7% 3.7% 3.7% 3.7% 3.7% 3.7% 3.7% 3.7%
1
No rate change assumed for 2019 - cost impact is covered by the subsequent year rate increases.
2
Average rate increase plus estimated rate change for carbon cost.
As noted, the Electricity Act calls for NB Power to achieve a minimum debt-to-equity ratio of 80/20. NB Power’s Strategic Plan 2011-2040
identified the opportunity to achieve this capital structure by 2021. The current update to the 10-year plan focuses on making steady annual
progress towards achieving this goal. However, various operating pressures and increased capital expenditure requirements will result in a delay
in meeting this internal capital structure target until 2024 - 2025, while still maintaining NB Power’s commitment to low and stable rate
increases.
Rate increases are modelled throughout the timespan of the 10-year plan to allow for progress to be made in the debt-to-equity ratio while also
working towards reducing absolute debt levels. Although progress is made in the debt-to-equity ratio in the early years of the plan, net debt
increases slightly as a result of capital investment requirements and relatively low net earnings. Should climate change initiatives proceed as
proposed, additional rate increases may be required to be implemented. The magnitude of any such rate increases will become clearer as further
details emerge from both the federal and provincial governments.
As noted, capital expenditures included for the Mactaquac project are reflective of the life achievement option. There are various approaches
associated with the life achievement option, with different spending amounts and varying timing for capital expenditures. This 10-year plan
includes a provision that is representative of the estimated lower end of the range of costs. The current estimated spending profile of this option
has major spending commencing in 2027 and continuing to 2036 (total expenditures of approximately $2.7 billion). As NB Power’s debt-to-equity
ratio improves beyond the minimum legislated target of 80/20 beginning in 2025, this improved capital structure will allow for more financial
3flexibility. This will help the utility to better prepare for the impact and potential variability of the Mactaquac costs, the uncertainties around the
cost of meeting climate change targets, and other future investment requirements.
Additional information on details of the 10-year plan and the assumptions contained within can be found in the sections following and in the
included appendices.
NB Power is a Crown corporation, an agent of the Crown and is the largest electric utility in Atlantic Canada. NB Power is responsible for
supplying energy to over 400,000 direct and indirect customers by way of over 21,000 km of distribution lines, substations, terminals and
switchyards that are interconnected by over 6,800 km of transmission lines. NB Power has developed one of the most diverse generation fleets in
North America to meet the unique daily and seasonal power needs of New Brunswick. Electricity requirements are supplied by 13 generating
stations spread throughout the province, through wind and other third-party power purchase agreements (PPA’s), or by importing electricity
from neighbouring jurisdictions when markets are favourable.
NB Power has four main operating divisions
Customer Service – Responsible for delivering safe, reliable and reasonably priced energy to customers
Generation – Maintains and operates the diverse system consisting of 12 hydro, coal, oil and diesel-powered generating stations
Nuclear – Maintains and operates the Point Lepreau Nuclear Generating Station (PLNGS), the only nuclear facility in Atlantic Canada
Transmission & System Operator – Responsible for maintaining and operating the terminals, switchyards and interconnected
transmission lines, as well as ensuring a reliable system is maintained
A Corporate Services department also exists that provides strategic direction, communications, finance, legal, human resources, supply chain,
and other various support services to the rest of the corporation. New Brunswick Energy Marketing Corporation, a wholly-owned subsidiary of
NB Power, conducts energy trading activities in markets outside New Brunswick, purchases electricity to serve load in New Brunswick and
standard offer service load outside New Brunswick, and markets excess energy generated in New Brunswick to other jurisdictions.
As a provincial Crown corporation, the owner and sole shareholder of NB Power is the Government of New Brunswick. NB Power reports to the
government through the Minister of Energy and Resource Development. The government’s expectations are expressed through legislation,
policies and mandate letters.
Additional information on NB Power can be found on our corporate website at www.nbpower.com.
4NB Power’s mandate is set by the Electricity Act. Specifically, section 68 provides direction regarding
Rates charged by NB Power for sale of electricity within the province
The management and operation of NB Power’s resources and facilities for the generation, supply, transmission and distribution of
electricity within the province
The Electricity Act also establishes that, to the extent practical, rates charged by NB Power for sale of electricity within the province shall be
maintained as low as possible and changes in rates shall be stable and predictable from year-to-year.
In addition, the Minister, by way of a mandate letter, has given NB Power the responsibility for delivery of the following
Maintaining and creating jobs in the resource sector in an economically sustainable fashion
Working with the other Atlantic Provinces and neighbouring jurisdictions to improve regional cooperation
Working with the federal government in ongoing investment and energy-related issues
Meeting debt reduction targets as established in NB Power’s 10-year plan
Protecting and improving the environment
NB Power is committed to a vision of sustainable electricity for future generations. NB Power’s mission is to be our customers’ partner of choice
for energy solutions. There are four core values that are essential to the utility’s success: Safety, Quality, Diversity and Innovation.
NB Power’s Board of Directors and management developed a long-term strategic plan as a foundation for NB Power’s business plans, investment
decisions and business initiatives. At the core of the Strategic Plan are three strategic objectives that guide the utility’s actions and will help
enable the achievement of the corporate mission and vision.
5Strategy One: Become Among the Best at What We Do
NB Power remains committed to becoming among the top-performing utilities in North America. For NB Power, becoming a top performer
means excelling in a number of critical areas including safety, customer service, organizational, reliability, and environment. To strengthen the
efforts to achieve excellence, NB Power has established an overall Excellence Framework. While in the early stages of implementation, this
framework will help NB Power to chart a path to becoming top quartile in these key areas over time.
Strategy Two: Reduce Our Debt so We can Invest in the Future
NB Power has committed to a reduction in debt over the 10-year plan period. This reduction in debt will represent a significant improvement to
NB Power’s capital structure and better align with other top performing crown-owned utilities. Through this debt reduction, NB Power will
reduce its exposure to rising interest rates and help ensure there is financial flexibility to make necessary investment decisions in the future.
Strategy Three: Reduce and Shift Electricity Demand
New Brunswick’s use of energy is highly seasonal and also can swing significantly at certain times of day. The Integrated Resource Plan (IRP)
outlines our energy needs for the next 25 years and current projections reflect a need to address supply and demand issues within this time
frame. Emerging technology and environmental factors are also introducing significant changes to the energy industry and marketplace. This
strategy and its associated initiatives are intended to help guide NB Power through this industry evolution and secure sustainable energy services
for our customers.
By executing on these three strategic objectives, NB Power will continue to provide value to the Province of New Brunswick and our customers
and position ourselves as a North American leader in innovation in the electricity sector. Additional information on NB Power’s strategic plan can
be found on the NB Power website at the following link: https://www.nbpower.com/en/about-us/accountability-reports/strategic-plans/
6NB Power’s Integrated Resource Plan (IRP) is a long-term plan that considers economics, the environment, long-term societal interests and
various sensitivities of these features. The most recent IRP extends to 2041/42 and a copy can be found on the NB Power website at:
https://www.nbpower.com/en/about-us/accountability-reports/strategic-plans/
IRP analysis is part of a continual process that requires periodic load and resource estimate updates as conditions evolve and change over time.
The 2017 IRP (see Figure 2) provides information regarding the strategic course of action that NB Power should consider to meet future resource
requirements.
Energy efficiency, demand management and grid modernization through the Energy Smart NB (ESNB) plan (formerly known as RASD) is
vital to the IRP. The IRP has included an aggressive but cost-effective, capacity and energy reduction schedule that assumes a savings of
approximately 620 MW and 2.3 TWh by 2041/42. This electricity reduction potential provides a significant net present value to NB Power
and to New Brunswick ratepayers over the IRP period.
A significant change is occurring in the electricity industry because of new and evolving customer options and personalized choices that
will change their electricity consumption. This trend will continue and a new partnership with customers will be developed in the near
term. The ESNB plan will be the catalyst to this new partnership.
Through the Province of New Brunswick’s Electricity from Renewable Resources Regulation, 80 MW of cost-effective Locally-Owned
Renewable Energy Projects that are Small Scale (LORESS) community resources and 13 MW of customer-owned Embedded Generation
are targeted by 2020. These programs along with ESNB will help meet the Regulation’s 40 per cent Renewable Portfolio Standard)
requirement.
Greenhouse gas (GHG) levels for the IRP planning period remain below 2005 historical levels.
Life extension of the Millbank and Ste. Rose generating stations in response to their planned retirements in 2031 is the most economic
choice for meeting continued peak load requirements.
Mactaquac’s continued operation is reflected through life achievement activities culminating in 2068.1
The planning period of the 2017 IRP extends to 2041/42, which includes the retirement of the Point Lepreau, Belledune and Coleson
Cove generating stations. It is recognized that significant investment will be needed to replace these assets. NB Power will look for
opportunities to separate and spread this investment over a broader period.
NB Power will continue to monitor existing supply technology options and costing, as well as emerging technologies to ensure the latest
information is available for subsequent IRP’s as the need for new supply requirements approaches.
1
Analysis supporting the Mactaquac life achievement option has been completed and will be filed with the EUB as part of a separate review application.
7Figure 2: Integrated Resource Plan
FY Ending Integrated Resource Plan Scheduled Retirements
2018 Energy Smart NB plan (-621 MW over period)
2019
Embedded Generation (+13 MW)
2020
LORESS (+80 MW)
…
2025 Grandview (-95 MW)
2026 Grand Manan (-26 MW)
2027 Bayside (-277 MW)
…
2031 Millbank / Ste Rose (+3 x 99 MW) Millbank / Ste Rose (-496 MW)
2032
2033 Mactaquac Life Achievement
…
2040 Lepreau Replacement-in-Kind (+660 MW) Point Lepreau (-660 MW)
Natural Gas Combined Cycle (+3 x 412 MW) Belledune (-467 MW)
2041
Millbank / Ste Rose (+2 x 99 MW) Coleson Cove (-972 MW)
2042
In summary, the strategic direction recommended by the IRP over the immediate term is
Continued development of the LORESS and Embedded Generation programs to meet the Renewable Portfolio Standard
Continuation of the ESNB plan with increased development in the long term
Continuation of technical work with regards to new generation options and business models that might be viable in New Brunswick,
especially options from customer-owned renewable resources
The assumptions contained within this 10-year plan are consistent with the IRP noted above.
8The assumptions incorporated into this 10-year plan were compiled based on a combination of information obtained from internal resources,
market indications and from external consultants or publications. A listing of key assumptions is provided in Appendix A. A table outlining the 10-
year plan’s sensitivity to changes in certain significant key assumptions is also presented in Appendix B.
Mactaquac Project Sensitivity
As noted, this 10-year plan is reflective of the life achievement option with respect to Mactaquac. There are, however, various approaches to
Mactaquac life achievement that have been assessed. These approaches vary with respect to the specifics of the work to be completed, total
spending requirements and timing of expenditures. For planning purposes, the lower end of the range of estimated costs has been reflected in
this 10-year plan. Figure 3 below provides some sensitivity information to illustrate the changes to the 10-year plan that would occur if the higher
end of the range of estimated costs were modelled (assuming the same general rate increases). The variances in capital requirements, revised
net income, net debt and percentage debt in capital structure have been presented for informational purposes.
Figure 3: Mactaquac Project Sensitivity
Fiscal Year Ending March 31 (in millions $) 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1
Upper Range of Estimated Capital Expenditures $ 11 $ 4 $ 11 $ 38 $ 166 $ 167 $ 253 $ 320 $ 233 $ 303
Capital Expenditures included in Plan 2 11 4 11 11 14 17 50 56 364 310
Variance $ - $ - $ - $ 27 $ 152 $ 150 $ 203 $ 263 $ (130) $ (8)
Revised Financial Highlights
Net Earnings 62 61 102 107 98 111 84 129 97 96
Net Debt 4,911 4,916 4,813 4,762 4,800 4,785 4,849 4,902 4,994 5,132
% Debt in Capital Structure 89.5% 88.5% 86.7% 84.9% 83.5% 81.9% 81.0% 79.4% 78.5% 77.8%
1. The upper limit estimate assumes rate recovery starting in fiscal year 2022.
2. The estimate included in the plan assumes rate recovery starting in fiscal year 2028.
9In the normal course of operations, NB Power’s net earnings can vary significantly from forecasted results due to changes in factors such as fuel
and purchased power prices, foreign exchange rates, interest rates, weather, hydro flows and various other risk items. Some of the key factors
that could significantly impact actual results are as follows:
Point Lepreau Nuclear Generating Station Capacity Factor – Fuel and purchased power costs could differ materially if the assumed PLNGS
capacity factor is not achieved.
Export Contracts – The 10-year plan assumes that NB Power will renew certain existing export contracts as they expire and achieve certain
margins on these contracts. Failure to be the successful bidder of these contracts or to renew at forecasted margin levels will impact results.
Market Conditions – Volatility in near-term fuel and purchased power prices and the Canadian dollar is largely managed through NB Power’s
financial hedging program. However, in the mid to long term , NB Power is exposed to changes in commodity prices and exchange rates.
Interest Rates – Given NB Power’s debt levels, volatility in interest rates can have a significant impact on results as existing debt issues mature
and need to be refinanced, as new debt needs to be issued to cover significant capital expenditures and/or as short-term debt costs fluctuate
based on market movements.
Natural Gas Supply – Uncertainty exists around the future source of supply and related pricing of natural gas. This 10-year plan is based on
current estimates for the future pricing of natural gas. Variations in actual supply and price from assumptions could result in fluctuations in fuel
and purchased power costs.
Economic Conditions – If future load growth falls short of the forecast or if there are unanticipated industrial closures, this could materially
impact forecasted in-province revenue.
Used Nuclear Fuel Management and Decommissioning – Liability and funding estimates for used nuclear fuel management reflect current
engineering estimates and standards. These estimates include cash flows which extend out over 150 years and are therefore subject to change.
Revised estimates could impact annual used nuclear fuel management and decommissioning costs, as well as overall funding requirements.
Hydro Generation – The 10-year plan is based on expected long-term average hydro flows. When actual hydro flows are below anticipated levels,
other more expensive fuels are used to account for the generation shortfall, thereby increasing in-province generation costs and/or reducing
energy available for export. Conversely, when hydro flows are higher than forecast, surplus hydro generation reduces the use of more expensive
fuels and decreases overall generation costs. Hydro flows that differ substantially from long-term average can therefore materially impact fuel
and purchased power costs.
10Regulatory Framework - The Electricity Act includes a regulatory framework that subjects all of NB Power to oversight by the EUB and requires
NB Power to seek annual approval of its rates (regardless of the amount of any rate change). All of the forecasted annual rate increases included
in this 10-year plan are therefore subject to EUB approval. If some portion of the forecasted rate increases were ultimately not approved, then
revenue projections could vary materially. A reduction in a forecasted rate increase in the earlier years of the 10-year plan can significantly
impacts results over the duration of the plan due to the cumulative impact that a rate adjustment can have in future years.
Mactaquac Project - Projected net earnings and debt levels are subject to change based on the final approval of the recommended life
achievement option for Mactaquac. Final cost estimates and the timing of expenditures will be reviewed through a regulatory process.
System Reliability and Risks – The 10-year plan is based on specific assumptions around planned plant outages and interconnection
opportunities with neighbouring utilities. Any unplanned interruption of generation facilities or interconnection points may result in additional
costs to NB Power for fuel and purchased power.
Carbon Costs – This 10-year plan has separately illustrated a preliminary estimate of the potential cost of carbon pending federal and provincial
legislation. The implementation of climate change actions during the forecast period could materially impact fuel and purchased power costs,
export revenues and/or future capital expenditure requirements.
11NB Power’s costs are driven by the cost of fuel and purchased power, costs required to run and maintain operation of the utility, capital
investments and recovery of regulatory deferral account balances. NB Power’s forecasted revenues, expenses and net earnings for the 10-year
plan period are presented in Figure 4.
Figure 4: Forecasted Revenue Requirement
Fiscal Year Ending March 31 (in millions $) 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Revenue
Sales of Power
In-province $ 1,453 $ 1,484 $ 1,536 $ 1,558 $ 1,585 $ 1,593 $ 1,611 $ 1,625 $ 1,646 $ 1,662
Out-of-province 178 185 175 163 171 179 185 183 191 192
Miscellaneous 74 77 80 87 91 96 102 106 109 113
Total Revenue 1,705 1,746 1,790 1,808 1,847 1,869 1,898 1,914 1,946 1,967
Expenses
Fuel and Purchased Power 597 601 621 602 631 616 659 608 657 642
Operations, Maintenance and Administration 499 506 475 492 508 522 511 524 525 539
Depreciation 274 305 317 324 324 324 326 329 333 351
Taxes 45 46 47 48 49 50 51 52 53 54
Total Expenses 1,416 1,458 1,460 1,466 1,511 1,511 1,547 1,513 1,569 1,585
Earnings before Undernoted Items 290 288 329 342 336 358 351 401 377 381
Finance Charges and Other Income 216 221 216 214 215 212 200 188 169 181
Net Changes in Regulatory Balances 11 6 11 18 18 19 41 42 44 46
Net Earnings $ 62 $ 61 $ 102 $ 110 $ 103 $ 127 $ 111 $ 170 $ 164 $ 155
Sales of Power - In-Province
Load in New Brunswick is forecasted to grow minimally during the 10-year period. Normal growth is partially offset by the impact of ESNB
programs. These programs are expected to reduce annual energy consumption in the province by approximately 1.2 TWh by 2028.
The increase over the period to in-province sales is largely related to the assumed rate increases implemented. Annual rate increases of two per
cent are modelled annually up to 2023 and then one per cent annually thereafter in pursuit of achieving a capital structure of at least 20 per cent
equity. This will better prepare NB Power for future rate impacts of the Mactaquac project and other cost uncertainties. Planned rate increases
are uncertain pending the final Mactaquac decision and impact of the related cost estimates, as well as the potential implications of climate
change initiatives. Refer to the In-Province Load section for additional information on load growth and rate increases.
12Sales of Power - Out-of-Province
NB Power takes advantage of its geographical location and diverse generation mix to sell surplus energy into neighboring jurisdictions such as
Prince Edward Island, Nova Scotia, Quebec and New England. Out-of-province sales benefit in-province customers by keeping rates lower than
they otherwise would be.
The 10-year plan assumes that all excess capacity is used to export energy when it is economic to do so (i.e. when market prices are forecasted to
be higher than the cost to supply). Management has used its best estimate on the expected ability to retain or renew existing export contracts
for the forecast period, considering NB Power’s historical relationship with external parties and any competitive advantage in the marketplace
that NB Power may have. The 10-year plan does not reflect new export contracts or other sales arrangements.
Miscellaneous Revenue
Miscellaneous revenue is comprised mainly of revenue derived from water heater rentals, transmission tariff, connection and surcharge fees,
pole attachment fees, third-party work performed for other utilities, customer contributions and forecasted margins for new products and
services. The 10-year plan includes a high-level estimate for increases in margin attributed to new products and services. The amount and timing
of these are subject to change, depending upon the success and ultimate timeline of the specific offerings to be marketed. Miscellaneous
revenue increases over the period mainly due to the increase in new products and services, increased transmission tariff revenue, and other
general increases due to assumed escalation.
Fuel and Purchased Power
Fuel expense reflects the cost of oil, coal, petroleum coke and diesel fuel used in NB Power’s thermal stations, as well as the cost of uranium used
at the PLNGS. NB Power also purchases energy and capacity under long-term agreements from wind, hydro, biomass and natural gas generators
in the province, as well as through market electricity purchases from utilities in neighbouring jurisdictions.
Fuel and purchased power expense variances over the forecast period are driven by
Changes to in-province load and export sales volumes
Changes to forecasted commodity and market prices
Biennial maintenance outages at PLNGS
Biennial maintenance outages at Belledune
Operations, Maintenance & Administration (OM&A)
OM&A includes labour, materials, hired services, travel, insurance and other costs associated with operating and managing the utility. NB Power
is committed to continuous process improvement and cost management by way of process reviews and efficiencies, regional collaboration,
technology improvements and automation.
Generally, OM&A expense is expected to increase annually by inflation throughout the 10 years, which is forecasted at two per cent. Other year-
over-year swings are largely reflective of the implications of the biennial maintenance outage cycle for PLNGS and Belledune, which results in a
13higher allocation to capital assets during an outage year. Increases in OM&A expense are partially offset by an assumed increase in process
improvement savings, driven both by savings from ESNB related initiatives and a commitment to continuous improvement. Over the period of
the 10-year plan, the amounts for process improvement savings increases from roughly $10 million to over $40 million annually.
Depreciation
Depreciation expense is driven by NB Power’s investment in capital assets and is based on expected useful service lives and the straight-line
method of depreciation. Depreciation expense also reflects a component of charges to income to account for the future decommissioning of
generating stations and the management of used nuclear fuel. Depreciation expense increases over the forecast period due to ongoing
investments in generating stations, ESNB related capital expenditures, and investments in transmission and distribution (T&D) infrastructure.
Taxes
NB Power is subject to property tax, utility tax and right of way tax. Taxes are assumed to escalate at modest rates during the forecast period.
Finance Charges and Other Income
NB Power uses a combination of long and short-term debt to finance its operations and all principal and interest is payable to the Province of
New Brunswick. As a result, NB Power incurs a debt portfolio management fee (0.65 per cent of debt outstanding at the end of the prior fiscal
year) that is also payable to the province as a result of these borrowing arrangements.
Other components of finance charges and other income help offset interest expense and the debt portfolio management fee. These include
earnings on investment and sinking funds, as well as interest during construction which capitalizes interest on funds expended on capital projects
not yet in service (i.e. work-in-progress).
Finance charges also include an expense that recognizes the time value of money on the estimated expenditures for decommissioning and used
nuclear fuel management liabilities. This is generally referred to as accretion expense and essentially represents an annual interest charge on
these forecasted liability balances.
During the 10-year plan period, both long- and short-term interest rates are expected to increase, resulting in higher interest expense. Accretion
charges also increase over time due to increasing liability balances. These cost increases are offset or partially offset in some years by a reduction
in overall debt levels and higher earnings on the investment and sinking funds. Finance charges also decrease towards the end of the period due
to an increase in interest during construction related to the Mactaquac project.
Net Changes in Regulatory Balances
Regulatory Deferral – PLNGS Refurbishment
Pursuant to the Electricity Act, certain costs incurred during the PLNGS refurbishment outage were accumulated and capitalized as a regulatory
asset and are now being amortized and recovered from customers over the life of the refurbished station.
14Regulatory Deferral – PDVSA Settlement2
In August 2007, the EUB approved the implementation of a regulatory deferral account to enable the savings associated with the lawsuit
settlement with PDVSA to be provided to customers on a levelized basis over a period of 17 years to 2024. In 2025, the net changes in regulatory
balances amount therefore increases as the benefit allocated to customers resulting from the PDVSA settlement is completed in 2024.
Regulatory Deferral – Other
As part of the rollout of advanced metering infrastructure (AMI), certain existing meter costs are expected to be written off as meters are
removed from service and replaced with smart meters before the end of their assumed life. For planning purposes, a portion of these expenses
have been assumed to be deferred and the expense recognized evenly over the period between 2020 and 2024. The establishing of such a
deferral account will require regulatory approval by the EUB.
During the summer of 2016, NB Power completed a 10-year Load Forecast for the 2018 to 2027 period. The key assumptions used in this forecast
include
Average Gross Domestic Product growth of 1.0 per cent annually based on the provincial government’s Economic Outlook released in
March 2016
Known major industrial additions and load changes based on account manager input and public announcements
The addition of approximately 14,500 new year-round residential customers by 2027 based on historical customer growth trends and
population projections
Normal weather (4,650 heating-degree-days) based on a rolling average using the latest 30 years
Penetration of electric space heating, water heating and air conditioning based on NB Power’s 2013 Energy Planning Survey of residential
customers
Estimates of energy reduction from NB Power’s ESNB plan, including smart grid innovations and energy efficiency programs were updated in the
summer of 2017 to reflect new information and to align with the 2017 IRP. Programs within the ESNB plan are forecasted to reduce energy
consumption in the province by 1.2 TWh by 2028. Figure 5 shows the total forecasted in-province load and year-over-year growth. The impact
that this reduction has on future supply requirements in the IRP is illustrated in Figure 6.
2
Petróleos de Venezuela, S.A. (Petroleum of Venezuela) is the Venezuelan state-owned oil and natural gas company.
15Figure 5: Forecasted In-Province Load
Fiscal Year Ending March 31 (in GWh) 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
In-Province Load
Residential 5,307 5,314 5,316 5,296 5,273 5,253 5,250 5,256 5,262 5,278
Industrial 4,293 4,359 4,629 4,608 4,605 4,580 4,582 4,568 4,585 4,561
General Service 2,349 2,327 2,312 2,288 2,268 2,253 2,253 2,258 2,265 2,266
Wholesale 1,268 1,266 1,265 1,267 1,271 1,273 1,277 1,280 1,285 1,280
Street Lights 44 44 45 45 45 45 46 46 46 46
Sub-total 13,262 13,310 13,566 13,503 13,462 13,404 13,407 13,407 13,443 13,430
System Losses 842 841 848 844 842 838 838 840 837 839
Total In-Province Load 14,104 14,152 14,414 14,347 14,304 14,243 14,245 14,247 14,280 14,269
In-Province Load Growth
Residential 0.9% 0.1% 0.0% -0.4% -0.4% -0.4% -0.1% 0.1% 0.1% 0.3%
Industrial -0.5% 1.5% 6.2% -0.5% 0.0% -0.6% 0.1% -0.3% 0.4% -0.5%
General Service -1.2% -0.9% -0.7% -1.0% -0.9% -0.6% 0.0% 0.2% 0.3% 0.0%
Wholesale 0.6% -0.2% -0.1% 0.1% 0.4% 0.2% 0.3% 0.2% 0.4% -0.4%
Street Lights 0.9% 0.5% 0.7% 0.7% 0.4% 0.4% 0.7% 0.2% 0.2% 0.3%
Total In-Province Load Growth 0.0% 0.4% 1.9% -0.5% -0.3% -0.4% 0.0% 0.0% 0.3% -0.1%
16Figure 6: Impact of Energy Smart NB Plan
17The Class Cost Allocation Methodology has been reviewed and approved by the EUB. Future rate increases will vary by customer class to
continue to move toward all customer classes being within a revenue-to-cost ratio of 0.95 – 1.05 (range of reasonableness). Although future rate
increases may be different by rate class, the overall aggregate increase will equal the average rate increase (i.e. 2 per cent). Figure 7 shows
average forecasted annual rate increases (excluding the potential impact of carbon costs), and the resulting revenue based on the sales
projections detailed in Figure 4.
Figure 7: Forecasted Annual Rate Increases and In-Province Revenue
Fiscal Year Ending March 31 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Average Rate Increase 2.0% 2.0% 2.0% 2.0% 2.0% 1.0% 1.0% 1.0% 1.0% 1.0%
Total In-Province Sales of Power ($millions) $ 1,453 $ 1,484 $ 1,536 $ 1,558 $ 1,585 $ 1,593 $ 1,611 $ 1,625 $ 1,646 $ 1,662
The 10-year plan calls for total capital expenditures of approximately $3.87 billion over the next 10 years. This total is inclusive of part of the
provision for Mactaquac in the range of $847 million. A final decision on the life achievement option for Mactaquac requires a regulatory review
and approval process.
NB Power is also planning to invest in technologies and processes to support the ESNB plan over the period of the 10-year plan. Additional
ongoing investments will also be required to maintain, upgrade and expand the generation and T&D assets that generate and deliver electricity
to customers throughout the province. A breakdown of forecasted capital spending is provided in Figure 8.
Figure 8: 10-Year Capital Plan
Fiscal Year Ending March 31 (in millions $) 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Mactaquac $ 11 $ 4 $ 11 $ 11 $ 14 $ 17 $ 50 $ 56 $ 364 $ 310
Energy Smart NB Projects
Smart Grid Technology & Capabilities 19 19 20 25 27 15 5 3 3 3
Advanced Metering Infrastructure 26 38 24 1 1 1 0 1 1 3
Digital Communications Network 4 3 1 1 1 1 1 1 1 1
Major Outage/Inspection Expenditures 70 75 67 52 49 42 47 43 50 53
General Capital Expenditures 213 235 168 233 233 215 212 194 262 259
Total Capital Expenditures $ 343 $ 374 $ 291 $ 322 $ 324 $ 291 $ 315 $ 298 $ 680 $ 630
18Mactaquac
A major capital project during the 10-year period revolves around the future of Mactaquac. Mactaquac produces about 1.6 TWh annually and can
produce 672 MW at full capacity. Since it was constructed in the late 1960’s, the Station has provided New Brunswickers with low cost, reliable,
emission free energy. However, in the 1980’s it was determined that a condition known as Alkali Aggregate Reaction (AAR) was causing the
concrete in the structures to slowly expand. The AAR growth rate has been steady and sustained over the past four decades. The present
expected end of service life for the concrete structures at the station with the current maintenance program is approximately 2030 based on
engineering estimates, while the original intended lifespan of Mactaquac was approximately 2068.
NB Power has evaluated the following options for addressing the projected condition of the concrete structures and equipment
Repower by replacing the spillway and powerhouse
No power and maintain the head pond by replacing the spillway but not the powerhouse
Remove the spillway, powerhouse and earthen dam
Operating the current concrete facilities beyond 2030, within the footprint of the existing facilities, through a modified intensive
maintenance program and replacement of aged equipment (“life achievement”)
The life achievement option has been proven to be technically feasible and is the option being pursued by NB Power. NB Power’s decision to
pursue this option follows three years of expert research, as well as input from First Nations and the public which resulted in several public
reports. An independent third party was engaged to review the decision making process and provided an expert report to NB Power’s executive
and Board of Directors. This decision follows a fact-based process balancing environmental, social, technical and cost considerations.
For modelling purposes, the lower end of the range of estimated costs for the life achievement option was selected as the basis for this 10-year
plan. As well as being the least cost option, major spending for the life achievement option does not begin until 2027 which is later than would
have been the case in some of the other options. In the coming years, NB Power will seek appropriate environmental approvals with the province
and follow application and review processes for financial approvals to be defined by the EUB.
Energy Smart NB
ESNB, formerly referred to as the “Reduce and Shift Demand” (RASD), is a long-term plan with the goal to fulfill the strategic objective of reducing
and shifting in-province demand for electricity and therefore ultimately deferring the next significant generation investment. The ESNB plan
includes three interrelated components
Smart Grid - Grid modernization technology and software, including engineering and design work, along with the internal process
changes and enhanced business capabilities required to implement and optimize the technology
Smart Habits - Demand-side management including energy efficiency and demand response programs
Smart Solutions - New products and services that leverage both demand-side management initiatives and smart grid technology, engage
consumers as more active participants in managing energy, and serve as new revenue streams for NB Power
19Smart Grid is the focus of investments in the capital plan. Many components of NB Power’s electricity grid are decades old and in need of
updating. New “smart” technologies are available that can improve the efficiency, flexibility and reliability of the grid while enabling important
new benefits. By modernizing the grid, NB Power can better understand how and when energy is being consumed and use that information to
operate more efficiently and provide customers with better service, new energy-saving products and services, and more flexible rate plans. In
addition, grid modernization lays the foundation for a wide range of reliability benefits, including more efficient outage response, which can
greatly aid in storm restoration, and enhanced ability to detect and correct issues on the grid before they affect customers.
Smart Grid is also essential to the expansion of renewable and distributed energy sources. As more variable energy sources are connected to the
grid, NB Power will face greater challenges in managing that variability to balance supply and demand while maintaining the stability of the grid.
By building smart technologies into the grid, NB Power can support greater customer participation in renewables while also improving reliability
and efficiency and offering customers more choice, control, and convenience as well.
AMI is a foundational technology required to modernize our grid. AMI enables a wide range of benefits made possible by a secure, two-way flow
of digital communications. Among many benefits, it provides usage information to customers so that they can manage their bills. It also enables
time-variant pricing to encourage load shifting, supports demand response programs for reducing and shifting load, and provides visibility to
customer outages. Within NB Power’s day-to-day operations, AMI will also increase efficiency of meter data collection, billing and
disconnects/reconnects. Power restoration times will also improve as a result of immediately knowing when a customer’s power is out and
having access to additional information to better pinpoint the cause of the outage.
A robust Digital Communications Network is required to support smart grid technologies and AMI. Traditionally, the primary role of digital
communications has been to support transmission operations. The next stage will be to modernize and extend this capability to the edge of the
distribution grid. The distribution substation will therefore become a key location for Digital Communications Networks. A coordinated approach
will allow NB Power to take advantage of smart grid technologies in support of ESNB, as well as other opportunities requiring connectivity
throughout the network.
Grid modernization efforts comprise the foundation enabling investments in ESNB infrastructure. This infrastructure supports development of
efficiency and demand response programs, and development of products and services that drive revenue program and operational
improvements in the field. In turn, the revenue programs, efficiency and demand response programs, and operational improvements drive
customer benefits, which include lower costs and higher quality service.
Major Outage / Inspection Expenditures
Major outage and inspection expenditures are the forecasted costs for planned outages and inspections at NB Power’s nuclear and thermal
generating stations. These costs reflect periodic outage assumptions for PLGNS and Belledune, as well as various other outage costs associated
with the remaining thermal facilities.
20General Capital Expenditures
NB Power’s 10-year capital plan has been strengthened through the corporate-wide adoption of standard project management methodology.
This includes a more robust process during the identification phase of projects and factoring continuous improvement into future capital
planning. NB Power’s investment governance framework includes capital review committees at both the corporate and divisional levels. The
corporate level committee is responsible for oversight of the framework and both the corporate and the divisional level committees are
responsible for vetting capital requirements within the 10-year plan.
NB Power is forecasting general capital expenditures of an average of approximately $222 million per year over the next 10 years. Continuous
investments are required in the generating stations and T&D system to ensure reliability, the safety of employees and the public, and to meet
expected customer growth in the province. Annual expenditures on information technology, communications equipment, vehicles, tools and
equipment are necessary to support day-to-day operations.
In addition to ongoing capital investments made to sustain daily operations, NB Power also considers capital investments that are intended to
provide economic benefits (i.e. will reduce operating costs and/or increase revenues). NB Power’s investment governance process evaluates
potential projects across the Utility to determine which projects should be included in the capital plan within available capital and human
resource constraints.
NB Power’s capital projects and programs can largely be categorized as follows
Asset Reliability Projects - Include generation facility, substation, terminal and T&D system reliability and upgrade projects to address
equipment aging, obsolescence and reliability improvements. Also included in this category are vehicle purchases, tools and equipment
and property improvements.
Obligation-to-Serve Projects - Include work in response to customer demands, water heater purchases and a portion of planned system
improvements that are related to load growth, joint use (i.e. used by other utilities in the province) and load shift projects.
Safety and Regulatory Compliance Projects - Include replacement of deteriorated assets which are a potential safety risk and projects
that are required to maintain operating licenses or meet regulatory requirements (i.e. PLNGS).
Asset Optimization/Productivity Projects - Include improvement projects that typically have a short payback period and provide net
benefits and present value savings to the organization.
21In October of 2016, the federal government introduced a motion to support ratification of the Paris Climate Change Accord and in December
2016, the federal government released the Pan-Canadian Framework on Clean Growth and Climate Change. Among other things, this framework
proposes to set a national benchmarking requirement of $10/tonne of CO2 by 2018, which would rise by $10 each year to $50/tonne in 2022, in
order to help Canada meet the Paris Accord. Provinces can choose to meet this requirement either through directly pricing CO2 (in the form of a
tax) or they can adopt cap-and-trade systems which must meet the same annual emission reductions expected from the benchmark pricing
requirements. The Framework notes that provinces will have the flexibility in deciding how to implement carbon pricing, but the federal
government will provide a pricing system for any province that does not adopt one of the two systems by 2018. In addition to carbon pricing, the
federal government is also considering the early phase-out of all coal generation in Canada by 2030.
The implications of a price on carbon as outlined above could potentially result in significant increases in costs to NB Power. The impact of carbon
pricing could affect the financial results of the 10-year plan in a number of ways. The major cost considerations would include items such as
An increase in fuel and purchased power costs, both by way of a tax and also by way of an expected increase in electricity market prices
A decrease in the ability to export, reducing export margins
Increased renewable energy requirements, either through new builds or PPA’s
Potential transmission system reinforcements to ensure reliability and accommodate changes to transmission flows or import levels
Stranded asset costs of coal fueled power plants that may not be able to operate to the end of their expected lives
Although revenues from carbon pricing are to remain within the provinces of origin, it is not clear as to how or if those revenues would come
back to benefit ratepayers to offset some of the potential cost implications noted above or if these revenues could be used to fund future carbon
reduction projects such as increased renewable resources.
Additional analysis and an evaluation of potential mitigating actions are still required but a preliminary estimate of the impact on fuel and
purchased power costs was completed based on the carbon charge system proposed by the federal government. A system dispatch was rerun for
the 10-year plan period that included a carbon charge on emissions starting at $10/tonne in 2018 and rising to $50/tonne by 2022 with general
escalation thereafter. An increase was also assumed to occur in general market prices for electricity over the period, ranging from $5/MWh to
$25/MWh. The amounts vary by year on account of the biennial PLNGS outages, but the preliminary analysis identified an increase in annual fuel
and purchased power costs of roughly $40 million in 2018, increasing to upwards of $210 million by the end of the 10-year plan. It is possible that
some portion of these costs may be able to be reduced through mitigating activities but it is not known as to what costs or capital expenditures
would be required to reduce the charges. In any event, carbon pricing has the potential to significantly impact and alter this 10-year plan, the
magnitude of which will become clearer as further clarity and details emerge from the federal and provincial governments.
As part of the 2017 IRP, three sensitivities around greenhouse gas (GHG) regulation were studied. A carbon cap limiting annual emissions to
between 2.5 to 3.0 million tonnes would cost between $500 million to $800 million on a present value basis over the IRP study period of 25
years. As an extreme but plausible scenario, a system dispatch was rerun for the 25-year study period that included a carbon charge on all
22emissions starting at $10/tonne in 2018 and rising to $50/tonne by 2022 along with coal retirement by 2030. An increase was also assumed to
occur in general market prices for electricity over the period, ranging from $5/MWh to $25/MWh. The present value cost increase was
approximately $2.5 billion over the lifecycle period which included the capital cost associated with the advancement of new generation to
replace the early retirement of coal generation. The latter scenario would reduce average annual GHG emissions to approximately 2.5 million
tonnes but at much greater cost than the former scenario under a carbon cap system.
In response to feedback received during the 2017/18 rate hearing application, an initial scenario analysis was undertaken as part of the
development of this 10-year plan to demonstrate the potential effect on forecasted financial outcomes of reasonable variations in three
significant plan assumptions. Best and worst credible case scenarios were developed for realistically foreseeable variations in forecasted in-
province load3, hydro generation4 and PLNGS capacity factor5. These items were chosen for scenario analysis purposes as they have historically
proven to cause significant intra-year variability in financial outcomes. The positive case scenario assumed high in-province load, high hydro
output (+257 GWh) and an increase in the capacity factor for PLNGS (+7 days = ~2%). In contrast, the negative case scenario assumed low in-
province load, low hydro output (- 195 GWh) and a decrease in the capacity factor for PLGNS (-14 days = ~4%).
The current 10-year plan, based on forecasted assumptions (the “base case”), was then compared to the positive and negative scenarios. Analysis
identified that, in addition to the planned 2% rate increase required under the base case, the negative case scenario would require an additional
annual rate increase of approximately 1.17% (total annual rate increase of 3.17%) in order to end up with a debt-to-equity ratio in the range of
80/20 by the end of fiscal 2024. In contrast, the positive case scenario would enable a reduction of approximately 1.30 – 1.25% from the base
case planned annual rate increase (total annual rate increase of .70 - .75%). However, due to the higher or lower increases in the front end of the
10-year plan, the overall rate base changes and this results in rate increases needing to vary after fiscal 2024 to result in the same financial
position as the base case plan at the end of fiscal 2028.
Appendix C provides a summary of the key financial measure results under the various scenarios, with and without a change to the proposed rate
increase strategy. Several charts have also been provided to present the impact on net debt, the capital structure, and the impact to rates and
corresponding costs to customers.
The variables assessed in the scenario analysis are only a few of the variables that can significantly impact the future financial results of NB Power
and the potential cost impacts to customers. This analysis is not intended to be all encompassing but to demonstrate the impact of a few key
variables and to highlight that future forecasted results are subject to change. As time progresses, NB Power will endeavor to continue to evolve
the scenario analysis to include the impact of other additional variables.
3
A high and low in-province load forecast based upon the mean average per cent error that has been seen in historical load forecasts.
4
A high and low hydro generation output based upon a 90/10 percentile factor identified in the hydro study for a 10-year monthly moving average.
5
An increase or decrease in the availability of PLGNS in terms of days/year.
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