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New Brunswick Power Corporation[4] (French: Société d’énergie du Nouveau-Brunswick), operating as NB Power (French: Énergie NB), is the primary electric utility in the Canadian province of New Brunswick. NB Power is a vertically-integrated Crown corporation by the government of New Brunswick and is responsible for the generation, transmission, and distribution of electricity.[5]: 3  NB Power serves all the residential and industrial power consumers in New Brunswick, with the exception of those in Saint John, Edmundston and Perth-Andover who are served by Saint John Energy, Energy Edmundston,[6] and the Perth-Andover Electric Light Commission,[7] respectively.

Key Information

History

[edit]

The development of the electricity industry in New Brunswick started the 1880s with the establishment of small private power plants in Saint John, Fredericton and Moncton. Over the next 30 years, other cities successively electrified, so much so that in 1918, more than 20 companies were active in the electricity business, which left the province with wildly differing levels of services and prices. In Saint John for instance, the rates fluctuated between 7.5 and 15 cents per kilowatt-hour, depending on the location and the monthly consumption.[8]

Interwar period

[edit]

Recognizing the important role that electricity was about to play in economic development, Premier Walter E. Foster proposed the creation of a provincially owned electric company. The Legislative Assembly passed a bill to that effect. The New Brunswick Electric Power Commission (NBEPC) was created on April 24, 1920, under the ministry of Peter Veniot (Public Works). Immediately, the commission, headed by its first president, C. W. Robinson, launched the construction of a C$2 million hydroelectric dam at Musquash, west of Saint John. To supply the cities of Saint John, Moncton and Sussex, a 88 miles (142 km) long high voltage power line was also built.[9]

The new earth dam was completed on time, in 1922. But it could not withstand the 1923 spring flood and collapsed,[9] an accident which shattered a bit of confidence in the new commission. The building of a larger facility in Grand Falls, on the Upper Saint John River, was undertaken in 1926 by a subsidiary of International Paper Company and completed in 1930.[9] Electricity demand increased during that decade and more generation facilities were required to supply the province. The commission decided to take advantage of coal resources in the Minto area and built a plant near the mines. The Grand Lake Generating Station was commissioned in 1931 and then expanded five years later.[10]

Post-war era

[edit]
The floodgates of the Grand Falls generating station, during the annual freshet of the Saint John River.

Demand for electricity exploded during World War II and led to rationing in the late 1940s.[11] Meanwhile, the commission embarked on the construction of two major dams on the Saint John River, the Tobique and Beechwood generating stations, which were respectively commissioned in 1953 and 1955. See below regarding First Nations relations.

The New Brunswick Electric Power Commission bought the Grand Falls Generating Station in 1959[11] and began work on the province's largest hydroelectric facility, the Mactaquac dam, whose first three units were put on stream in 1968.[12]

However, the new hydroelectric developments proved insufficient to bridge the imbalance between supply and demand, which grew by 12% per annum between 1960 and 1975. To cope with this demand growth, the commission began construction of the oil-fired Courtenay Bay Generating Station, near the Saint John shipyard in 1959; it was also adjacent to the Irving Oil Refinery, which entered service in the late 1950s and which the Courtenay Bay Generating Station made use of a pipeline running from the Canaport offshore loading facility at Red Head to the refinery. The first 50 MW turbine was put in service at Courtenay Bay Generating Station the next year, in December 1960, while two more units were added in 1965 and 1966, 50 MW and 100 MW, respectively.[12] To better serve northern New Brunswick, another oil-fired plant, the Dalhousie Generating Station, was constructed in Darlington with an initial capacity of 100 MW. It was commissioned in 1969.[12]

In the early 1970s, the NBEPC signed a series of supply contracts with New England distributors, justifying the construction of its largest power plant in 1972. With three 335 MW units, the oil-fired Coleson Cove Generating Station was completed in January 1977. However, the 1973 oil shock made the operation of thermal plants more expensive, since oil prices rose from US$3 to US$37 per barrel between 1973 and 1982. The company, which was renamed NB Power / Énergie NB during that time, needed to explore other generating options.[13]

Point Lepreau

[edit]
Main article: Point Lepreau Nuclear Generating Station

The construction of a nuclear plant in New Brunswick had been discussed since the late 1950s. For over 15 years, engineers from the NBEPC visited the Chalk River Laboratories to keep abreast of the latest trends in the field.[13] Formal talks between the provincial and federal governments began in 1972 and discussions between representatives of Premier Richard Hatfield and Atomic Energy of Canada accelerated the following year. In the aftermath of the oil crisis, the province wanted to secure a source of electricity whose prices would be less volatile than oil. However, project financing was still an issue.[14]

The federal government then announced a loan program to help provinces such as New Brunswick in January 1974. Ottawa's pledge to cover half of the cost of a first nuclear plant removed the last obstacle to construction of the Point Lepreau Nuclear Generating Station. On February 5, 1974, Hatfield announced his decision to build the plant, 20 miles (32 km) west of Saint John, and even raised the possibility of constructing a second one in the future. On May 2, 1975, the Canadian Atomic Energy Commission authorized the construction of two 640-MW units within a site that can accommodate a maximum of four reactors.[14]

Labour unrest, design problems and skyrocketing construction costs significantly increased the plant's price tag. The total price of the first operational CANDU-6 in the world was estimated at 466 million dollars in 1974.[15] Inflation between 1978 and 1982 was 46%, this increased the costs for all infrastructure projects in Canada. Projects like Darlington Nuclear Generating Station and Point Lepreau had priced their estimates before the inflation. When it became operational 8 years later, on February 1, 1983, the cost had soared to C$1.4 billion.[14]

Proposed sale to Hydro-Québec

[edit]
Main article: Proposed sale of NB Power

On October 29, 2009, the premiers of New Brunswick and Quebec signed a memorandum of understanding to sell most of NB Power's assets to Hydro-Québec.[16] This agreement was reached after nine months of negotiations undertaken at the request of New Brunswick[17] and would have transferred most generation, transmission and distribution assets of the New Brunswick utility to a subsidiary of the Quebec-based Crown corporation, including the Point Lepreau Nuclear Generating Station and 7 hydroelectric plants, but would have excluded fossil-fuel fired plants in Dalhousie, Belledune, and Coleson Cove.[18]

The memorandum of understanding fostered a spirited public debate in New Brunswick and Atlantic Canada. Despite positive feedback from the province's business leaders,[19][20] many reactions to the MOU were hostile. Opposition parties, Newfoundland and Labrador premier Danny Williams,[21] the union representing most NB Power employees,[22] and wind energy supporters[23] quickly condemned the agreement as detrimental to the interests of New Brunswick.

Opponents in the general public used social media to show their displeasure and contest the various arguments for the deal. On Facebook, 14,000 people joined a group in opposition to the sale within five days of the announcement.[24] A demonstration organized by the group and trade unions drew approximately 600 people outside the Legislative Assembly building on November 17, 2009.[25] A Leger Marketing opinion poll conducted on behalf of Quebecor Media newspapers in New Brunswick and Quebec in November 2009 showed that 60% of New Brunswickers polled opposed the proposed sale, while 22% supported it.[26]

After months of controversy, New Brunswick and Quebec representatives signed a second agreement in January 2010, reducing the scope of the sale. Under the revised agreement, the sale would have transferred NB Power's hydroelectric and nuclear power plants to Hydro-Quebec for C$3.4 billion. The government of New Brunswick would have retained the transmission and distribution divisions of NB Power, and the Crown corporation would have entered into a long-term power purchase agreement (PPA) with Hydro-Québec. The PPA would have allowed NB Power to deliver the rate freeze for residential and general customers. However, the industrial rates rollback would have been smaller than under the original MOU.[27]

On March 24, 2010, Premier Graham announced the failure of the second agreement due to Hydro-Québec's concern over unanticipated risks and costs associated with matters including dam security and water levels.[28] This interpretation was contested by analysts, who blamed the collapse of the deal on the political situation in New Brunswick.[29][30]

Corporate structure

[edit]
A NB Power lineman working on a transmission tower in Saint John.

The future of NB Power has been a concern of successive New Brunswick governments for the past 15 years[when?]. The Liberal government of Raymond Frenette published a consultation document in February 1998 to find solutions to ensure the sustainability of NB Power in the twenty-first century.[31]

Valuation

[edit]

Shortly after taking office in 1999, the Conservative government of Bernard Lord commissioned TD Securities to conduct an assessment of the company's viability. The study, whose findings were published in 2009, suggested four scenarios: the status quo; a sale to a strategic buyer; privatization through a share offering; or splitting the utility into separate elements. The report valued the company at between $C3.6 and $C4.5 billion.[32] This number however was very strongly contested by those familiar with the value of telecommunications rights of way and smart grid-based services, energy-related and otherwise, who considered the distribution network to have very much more value. These arguments were to be repeated often in the 2009-2010 NB Power controversy.[citation needed]

Between 2001 and 2004, the Lord government spent C$3.2 million to retain the services of CIBC World Markets and Salomon Smith Barney in order to evaluate the resale value of the Point Lepreau and Coleson Cove power plants. The studies, codenamed Cartwheel and Lighthouse, have assessed the value of these assets to roughly C$4.1 billion.[33] A similar valuation was used in the failed 2010 proposal to vend Lepreau to Hydro-Quebec, and was extremely controversial.

2003 reorganization

[edit]

The Lord government shuffled the company's structure in early 2003 by introducing amendments to the Electricity Act.[34] The Act reorganized NB Power into a holding company with four divisions: NB Power Distribution and Customer Service, NB Power Generation, NB Power Nuclear, and NB Power Transmission. The Act maintained the company's distribution, transmission, and nuclear power monopolies, but opened the door to competition in the generation business.[35] The reorganization also created the New Brunswick Electric Finance Corporation, which was responsible for issuing, managing and paying NB Power's debt through payments dividends, fees and taxes paid by the various subsidiaries,[36] and the New Brunswick System Operator, an independent market operator that administered relationships between power generators and users.

2013 Reorganization

[edit]

The NB Power Group of Companies, the Electric Finance Corporation, and the New Brunswick System Operator merged on October 1, 2013, re-establishing NB Power as a single, vertically integrated Crown corporation.[5]: 4 

Personnel

[edit]

In October 2008, NB Power Holding Corporation was named one of "Canada's Top 100 Employers" by Mediacorp Canada Inc., and was featured in Maclean's newsmagazine.[37] In 2009, NB Power became the first electric utility to be recognized by the National Quality Institute by being awarded a Healthy Workplace Award.

David D. Hay resigned as President in 2010, claiming he had never been consulted on the proposed sale of NB Power, the valuations or the strategies involved.[citation needed] He was replaced by Gaëtan Thomas, the former Vice President of NB Power's Nuclear Division, who remained the President and CEO of NB Power till May, 2020. Keith Cronkhite was appointed NB Power President and Chief Executive Officer CEO on April 1, 2020.[38]

Lori Clark was appointed President and Chief Executive Officer (Acting) on July 4, 2022.

Operations

[edit]

Power generation

[edit]
Bayside Generating Station in Saint John
Further information: List of power stations in New Brunswick

NB Power operates 13 generating stations with a total installed capacity of 3,513 MW as of 2013.[39][40] The generation fleet uses a variety of energy sources: heavy fuel oil (972 MW), hydro (889 MW), uranium (660 MW), diesel (525 MW), and coal (467 MW).[40][41] As of 2020, NB Power's grid includes 355 MW of wind energy.[42]

The generation facilities are spread across the province. However, the Saint John, New Brunswick area accounts for nearly half of the total NB Power-owned generation capacity, with the Coleson Cove (972 MW), the Point Lepreau Nuclear Generating Station (660 MW), and Bayside Generating Station (277 MW).[41] Saint John is home to energy-intensive industries such as the Irving Oil Refinery, JD Irving pulp and paper mills, and the Canaport liquefied natural gas terminal.

Thermal generation

[edit]

NB Power operates two thermal and three combustion turbine facilities with a combined generating capacity of 1,964 MW.[43][41]

Nuclear generation

[edit]
Main article: Point Lepreau Nuclear Generating Station

NB Power operates the Point Lepreau Nuclear Generating Station which is the only active nuclear generating station in Canada outside of Ontario. It has a generation capacity of 660 MW.[44][41]

Hydroelectric generation

[edit]
The Mactaquac dam and generating station on the Saint John River, upstream from Fredericton.

NB Power operates seven hydroelectric dams in the province with a combined generating capacity of 889 MW.[40][41] The main hydroelectric facilities are located on the Saint John River.[41]

The province's largest, the Mactaquac generating station (668 MW), stands some 20 miles (32 km) upstream of the capital city, Fredericton. It was built between 1965 and 1968 at a cost of C$128 million.[12] The plant has been a concern for some time[when?] due to alkali-aggregate reaction, which is causing the dam to expand and crack. The problem has been known since the 1970s and could reduce the dam's life by half, according to a 2000 report by a panel of international engineering experts commissioned by the Crown corporation.[45]

Electric transmission

[edit]
Transmission lines near the Point Lepreau Nuclear Generating Station, in southwestern New Brunswick.

NB Power's transmission grid includes over 6,849 kilometres (4,256 mi) of high voltage transmission lines ranging from 69 kV AC to 345 kV AC.[39][40] The company operates interconnections with Hydro-Québec, Nova Scotia Power, Maritime Electric in Prince Edward Island and the ISO New England network in the United States. The network is operated by the Transmission & System Operator division of NB Power.[40]

The main power grid forms an O-shaped loop with 345 kV lines. This power line runs through substations at Keswick, Saint-André, Eel River, Belledune, Bathurst, Salisbury, Valley Waters, Coleson Cove, Point Lepreau, and back to Keswick.[46] There is also a direct connection of a parallel 345 kV line between Coleson Cove and Keswick.

NB Power supplies electricity to Maritime Electric in Prince Edward Island through a sub-sea interconnection cable on the floor of the Northumberland Strait, and imports/exports from/to Nova Scotia via Canada's first electrical interconnection between two provinces. NB Power also has interconnections to Maine.

Because of the asynchronous nature of Hydro-Québec's electricity transmission system, interconnections between the two neighboring provinces require HVDC converters. The first one, the Eel River Converter Station, was installed in 1972 and has a 350 MW transfer capacity.[13] It is the first operative HVDC system equipped with thyristors[47] The second converter, the Madawaska substation (435 MW), was built on the Quebec side of the border in 1985 and is operated by Hydro-Québec TransÉnergie.[48] The two systems are linked by two 230-kV lines between Matapédia and Eel River, and by two 315-kV lines between the Madawaska and Edmundston substations. Some of NB Power loads in these areas can be islanded and supplied as part of the Quebec grid, which increases New Brunswick's import capability to 1,080 MW, whereas export capability to Quebec is limited to 785 MW.[49]

Coal mining

[edit]

Beginning in 1986, NB Power operated a coal mine in Minto through its NB Coal subsidiary.[48] The company extracted approximately 150,000 tons of coal per year to fuel the Grand Lake Generating Station, a 57 MW power plant built in 1963. On September 30, 2009, the company announced the planned closure of the mine and the decommissioning of the Grand Lake Generating Station. The company management explained the decision by stressing the high cost of complying with stricter SO
2 emission regulations.[50] The decommissioning and demolition of the Grand Lake Generating Station were completed in 2012.[39]: 15 

Financial results

[edit]
Financial Data 2017-1998 (year ending on 31 March)
millions of Canadian dollars[51][52][53][54][55][56]
2017 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998
Revenue 1,696 1,791 1,791 1,797 1,605 1,646 1,616 1,635 1,453 1,712 1,512 1,585 1,403 1,311 1,273 1,319 1,309 1,248 1,204 1,140
Net earnings (Net losses) 27 12 100 55 65 173 67 (117) 70 89 21 96 9 (18) (77) 20 (78) 17 (423) (21)
Dividends declared 11 16 9 13 13 11 10 12 5 0 0 0 0 0 0 0
Total assets 5,959 5,895 6,128 6,863 6,689 6,006 5,632 5,379 5,190 4,686 4,151 3,969 3,874 3,729 3,387 3,236 3,298 3,464 3,666 4,197
Long term debt 4,007 4,124 4,025 4,597 4,692 3,469 3,417 3,481 3,051 2,891 2,869 2,655 2,459 3,217 2,999 2,530 2,950 2,795 3,019 3,104

Investment concern

[edit]

In 2019, the utility was criticized for having invested $13 million in Joi Scientific, a Florida-based company that promised to deliver hydrogen-based power from seawater with 200% efficiency.[57] According to critics, their promised efficiency violated the first law of thermodynamics.[58] During a call with investors during the summer of 2019, Joi Scientific announced that their technology was perhaps only ~10% as efficient as previously described, meaning that their process consumes energy rather than producing it.[59] The company also announced that they were running low on funding.[57] Joi Scientific's technology has been described by a former employee as being based on the work of discredited inventor Stanley Meyer.[57]

See also

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References

[edit]

Further reading

[edit]
[edit]
Revisions and contributorsEdit on WikipediaRead on Wikipedia

NB Power

View on Grokipedia
from Grokipedia
NB Power, officially the New Brunswick Power Corporation, is the provincially owned crown corporation responsible for the generation, transmission, distribution, and retail sale of electricity to over 350,000 residential, commercial, and industrial customers throughout , . Employing more than 2,600 people, the utility manages 13 generating facilities with a net capacity of 3,799 megawatts, utilizing a diverse mix of hydroelectric (889 MW), nuclear (660 MW), (972 MW), diesel (525 MW), and (467 MW) sources, supplemented by farms and power purchase agreements. Established by provincial in 1920 with roots in 1880s private power ventures, NB Power has facilitated 's electrification and exports surplus energy to , , , and via an interconnected grid. Defining its operations are efforts to maintain reliability through projects like the Mactaquac Generating Station refurbishment, which extends hydroelectric capacity as the province's most cost-effective clean energy option compared to alternatives like or solar, alongside transitions toward lower-emission generation amid fiscal pressures from aging infrastructure and fuel costs.

History

Formation and Early Development (1920s–1940s)

The New Brunswick Electric Power Commission (NBEPC) was established on April 24, 1920, through the enactment of the Electric Power Act by the provincial legislature, aiming to develop and supply in areas underserved by private enterprises. The initial board comprised Chairman C.W. Robinson, Commissioner and Chief Engineer C.O. Foss, and Secretary Reid McManus, who oversaw the commission's formative operations amid a fragmented landscape of approximately 20 private power producers by 1918. The commission's first major initiative was the construction of a hydroelectric and powerhouse on the Musquash River, completed in spring 1922 at a cost of $2 million, which powered early customers including Fraser's at starting in 1921. An 88-mile transmission line from Musquash to Fairville and became operational in February 1923, extending service to communities such as , , and Saint John, though the project faced setbacks including a in spring 1923 due to heavy rains and snowmelt. During , the NBEPC diversified beyond with the Grand Lake thermal plant, commissioned in 1931 to utilize local Minto coal at a rate of 20,000 tons annually, primarily serving and Marysville; this shift addressed limitations in hydroelectric reliability amid growing industrial demand. Further expansions included a from Dalhousie to Belledune operational in October 1932, leveraging surplus power from the Company's facilities, and the acquisition of distribution systems in Newcastle and Chatham in 1934, powered by the Bathurst Company's Nepisiguit Falls . Concurrently, the private Saint John River Power Company, a subsidiary of , developed the Grand Falls hydroelectric , which opened in 1930 with rights granted earlier to exploit the site's potential. The constrained growth following the 1929 , prompting cautious infrastructure investments and disputes over coal pricing, exacerbated by the 1936 Minto miners' strike that disrupted Grand Lake operations. demands in the 1940s shifted priorities toward wartime support, including electricity supply to training bases and the installation of diesel generating units—such as a 50 kW unit in St. Quentin in 1940—in remote areas like St. Stephen, Andover, Campobello, Shippagan, and St. Quentin to ensure reliability. Under Chairman Robinson until his death in 1944, the NBEPC incrementally expanded as a focused on rural and municipal systems overlooked by private firms, laying groundwork for scaling while generating limited capacity relative to provincial needs.

Post-War Expansion and Nationalization (1950s–1970s)

Following , the Electric Power Commission (NBEPC) experienced rapid expansion driven by industrial demand from sectors such as pulp and paper and , necessitating significant investments in generation and transmission infrastructure. Between 1945 and 1948, the NBEPC constructed over 1,100 miles of transmission and distribution lines, nearly doubling its direct customers to approximately 17,000 by the late . Generating capacity stood at 112 MW in , with projections estimating a of 147 MW by 1961, prompting further development to avert shortages. Nationalization efforts accelerated through targeted acquisitions of private utilities, consolidating control under the commission and reducing fragmented private . In 1948, the NBEPC had already expropriated the Saint John plant from the New Brunswick Power Company; this continued in the 1950s with purchases of distribution systems in Bathurst and Dalhousie (1957–1958) and the Moncton Electricity & Gas Company (1959). The symbolic acquisition of the Grand Falls Generating Station in 1959 from private interests further centralized hydroelectric assets. Additionally, the Milltown dam and powerhouse were purchased in 1958, enhancing oversight of key facilities. These moves, financed initially through provincial bonds and later via government-guaranteed debentures, shifted the NBEPC toward greater operational autonomy from political , prioritizing efficient supply for industrial users. Hydroelectric development formed the core of 1950s expansion, with the Tobique Narrows project initiating construction in 1950 and completing the Tobique River dam by 1953 to bolster . The Beechwood Hydroelectric Project followed, breaking ground in June 1955 at a cost of $28 million (funded partly by federal loans), and opening on June 11, 1955, to meet surging industrial needs. Complementary thermal upgrades included a 20 MW expansion at the Chatham plant in 1955, converting from coal to oil for reliability. A major setback occurred in 1956 when a severe damaged 423 miles of distribution lines and 10 miles of 69 kV transmission, disrupting service to 23,000 customers and underscoring vulnerabilities. Into the , the NBEPC pursued large-scale projects amid growing export ambitions, establishing interconnections with utilities in 1960 for . Construction of the Courtenay Bay plant began in 1959, with its first 50 MW unit operational by December 1960 and the third unit (adding 100 MW total) completed in 1966. The flagship Mactaquac Generating Station project commenced in 1965 at a cost of $128 million, yielding 600 MW capacity with the first three units online by 1968, transforming the Saint John River for multi-purpose hydroelectric output. The Dalhousie Generating Station, a 100 MW facility, entered service in 1969. By the late , an export-led strategy emerged, leveraging surplus capacity for sales to neighboring regions. The marked a transition to and preparatory nuclear capacity amid escalating demand and price volatility. of the Coleson Cove Generating Station began in 1972, featuring three 355 MW -fired units operational by January 1977 for a total of 1,065 MW. The Eel River HVDC converter station, the world's first commercial solid-state facility, activated in 1972 to facilitate efficient long-distance transmission and exports. These developments positioned the NBEPC—fully nationalized through prior acquisitions—for the nuclear , though mounting debt from bond-financed expansions highlighted financial strains under provincial guarantees.

Point Lepreau Nuclear Station Era (1970s–2000s)

In response to growing electricity demand and the , Power decided to develop nuclear capacity, leading to the selection of Point Lepreau as the site for the province's first nuclear generating station. Construction began in 1975 on the CANDU-6 , designed to produce 635 megawatts of electricity, sufficient to meet about one-quarter of the province's power needs. The project, managed by Power as the provincially owned utility, involved collaboration with for the reactor technology. The station achieved criticality in 1982 and entered commercial operation in April 1983, marking the entry of into New Brunswick's energy mix and region. During the and 1990s, Point Lepreau operated reliably, contributing to NB Power's ability to supply stable base-load electricity amid fluctuating fossil fuel prices and hydroelectric limitations. The facility demonstrated strong performance, with a lifetime exceeding industry averages for CANDU reactors, supporting in the province without heavy reliance on imported oil. By the early 2000s, accumulating operational data indicated the need for major maintenance to extend the plant's life beyond its original design, prompting NB Power to initiate refurbishment planning in 2000. Initial cost estimates for the refurbishment were around C$750 million, focusing on replacing pressure tubes, steam generators, and other core components to ensure safety and efficiency. This era solidified nuclear power's role in NB Power's strategy, though it highlighted challenges in managing long-term capital investments for aging infrastructure. The decision to proceed with refurbishment was formalized in mid-2005, reflecting confidence in the technology's viability despite debates over costs and alternatives.

2010 Hydro-Québec Sale Proposal and Fallout

In 2009, New Brunswick Power (NB Power) faced significant financial pressures, including approximately $4.7 billion in debt accumulated from investments in aging infrastructure and the Point Lepreau nuclear generating station refurbishment overruns, which contributed to projected electricity rate increases of up to 15% annually without intervention. To address these challenges, New Brunswick Premier Shawn Graham negotiated a with Quebec Premier , announced on October 29, 2009, under which would acquire most of NB Power's non-nuclear generation assets—including seven hydroelectric facilities, two diesel peaking plants, and the Coleson Cove plant—for an initial estimated $4.75 billion. The arrangement aimed to eliminate much of NB Power's debt, cap residential rates at a 2010 freeze level with guaranteed stability for five years, and establish long-term power purchase agreements where NB Power would buy electricity from at capped prices while retaining responsibility for transmission and distribution. Proponents, including Graham, argued the deal preserved public ownership in New Brunswick by restructuring NB Power into a distribution-focused entity, avoiding to out-of-province investors. Public and emerged rapidly, with critics decrying the sale as a loss of provincial over key energy resources and potential vulnerability to Quebec's control over supply pricing post-agreement period. Concerns included underestimated liabilities such as decommissioning costs for thermal plants, at sites like Belledune, and uncertainties around Point Lepreau's reliability, which would not assume. Large-scale protests ensued, culminating in a rally of over 4,000 people in on March 20, 2010, amid polls showing majority opposition; NB Power board member David Alward resigned in protest, citing inadequate and risks to ratepayers. Independent analyses, such as from the Institut économique de Montréal, highlighted hidden costs for exceeding $1 billion in liabilities and forgone revenues, suggesting the deal undervalued NB Power's assets relative to their long-term hydroelectric output potential. Negotiations amended the terms in January 2010, reducing the price to $3.2 billion and excluding additional assets like the Millidgeville diesel plant, but ultimately withdrew on March 24, 2010, citing insurmountable unanticipated costs and demands for further concessions, including guarantees against NB Power's nuclear liabilities spilling over. The collapse stemmed from 's due diligence revealing higher-than-expected financial risks, including pension obligations and regulatory hurdles, which eroded the deal's viability despite initial political alignment between the provinces. The fallout included immediate financial strain on NB Power, with the province incurring $8 million in transaction costs for legal, advisory, and fees without realizing . Electricity rates rose by an additional 3% in April , contributing to cumulative increases exceeding 6% that year, as the utility resorted to short-term borrowing and deferred maintenance to manage its . Politically, the episode damaged Graham's credibility, factoring into the Liberal Party's defeat in the September provincial , where Progressive Conservative leader David Alward campaigned against the "fire sale" and promised fiscal reforms for NB Power. Long-term, the failed deal prompted internal reviews and regulatory scrutiny, including a Energy and Utilities Board hearing that voided prior approvals tied to the sale, while reinforcing provincial emphasis on diversifying generation to mitigate reliance on imported power.

Reorganizations and Modern Challenges (2010s–Present)

In response to ongoing financial pressures following the collapse of the acquisition proposal, the government enacted the Electricity Act in 2013, which facilitated the amalgamation of NB Power's subsidiaries—including the NB Power Group of Companies, the Electric Finance Corporation, and the System Operator—into a single vertically integrated Crown corporation effective October 1, 2013. This restructuring aimed to streamline operations and reduce administrative costs after a decade of unbundling into separate entities for generation, transmission, and distribution. Despite the reorganization, NB Power has faced mounting challenges from escalating and demands. Net stood at $4.3 billion in 2010 and grew to $4.9 billion by 2020, with a of 94%, failing to meet reduction targets partly due to overruns from the Point Lepreau Nuclear Generating Station refurbishment, which completed in 2012 at costs exceeding initial estimates by over $1.6 billion. By fiscal year 2023, total reached $5.4 billion amid annual losses of $43 million, prompting warnings from the about risks from consistent deficits and capital expenditures. Operational reliability at key assets like Point Lepreau has compounded financial strains, with the station experiencing an eight-month outage in 2024 for and stator bar repairs, returning to service on December 12, 2024, after delays that increased customer costs. An independent assessment ranked Point Lepreau as a poor performer in upkeep spending post-refurbishment, contributing to higher-than-average forced outage rates. To address revenue shortfalls, NB Power applied for rate hikes, including 4.75% effective April 2026—adding approximately $130 annually to average residential bills—followed by planned 6.5% increases in 2027 and 2028, reflecting broader pressures from aging infrastructure and net-zero transition mandates. In 2025, the provincial government launched a comprehensive review of to tackle high debt, rate affordability, and long-term viability, considering options such as debt assumption by the province or asset sales while prioritizing service reliability and emissions reductions under the 2023-2035 strategic plan. This initiative echoes earlier post-2010 efforts but underscores persistent structural issues, with net debt at $5.347 billion as of recent reporting and no fixed timeline for achieving the legislated 80/20 debt-to-equity target.

Governance and Corporate Structure

NB Power operates as a provincial Crown corporation, with the Government of serving as its sole owner and shareholder. This structure positions the utility as a vertically integrated entity responsible for , transmission, distribution, and within the , reporting directly to the provincial government through the Minister of Energy and Resource Development. As of 2025, the initiated a comprehensive independent review of NB Power's operations, governance, and potential structural alternatives, including involvement, amid ongoing financial and operational challenges. The legal framework governing NB Power is primarily established by the Electricity Act, S.N.B. 2013, c.7, which repealed prior legislation and restructured the utility into New Brunswick Power Corporation as the core operating entity under a framework. This Act mandates NB Power's responsibilities for maintaining a reliable integrated electricity system, promoting to transmission, and advancing integration, while emphasizing cost recovery through rates and accountability measures. The 2013 reforms aimed to enhance transparency, with requirements for public reporting on rates, capital expenditures, and performance metrics, replacing earlier acts like the 1975 New Brunswick Power Corporation Act. Regulatory oversight is provided by the New Brunswick Energy and Utilities Board (NBEUB), an independent established under provincial law to regulate electricity rates, approve rate changes, and review NB Power's general rate applications, capital projects exceeding $50 million, and long-term resource plans. The NBEUB enforces reliability standards, including those from the (NERC), and ensures non-discriminatory access to the , with authority to monitor compliance and impose conditions on major initiatives like new generating facilities. For nuclear operations, particularly the Point Lepreau Generating Station, additional federal oversight falls under the Canadian Nuclear Safety Commission (CNSC) pursuant to the Nuclear Safety and Control Act, focusing on safety, licensing, and environmental compliance. This dual regulatory structure balances provincial economic regulation with federal nuclear safeguards, though critics have noted tensions in approval processes for projects, as evidenced by the NBEUB's 2025 rejection of NB Power's request to bypass review for a proposed gas-fired plant.

Key Reorganizations and Structural Changes

In the 1970s, the Electric Power Commission underwent a to NB Power (Énergie NB Power in French), adopting a new featuring two orange revolving arrows to symbolize modern operations and energy flow, reflecting the corporation's expansion into and larger-scale generation projects. A significant structural overhaul occurred in 2003 through amendments to the Electricity Act (SNB 2003, c E-4.6), which reorganized NB Power into a structure, New Brunswick Power Holding Corporation, with four operational divisions: generation, transmission and distribution, customer service (retail), and nuclear operations. This restructuring aimed to facilitate potential competition in and retail markets while maintaining regulated monopolies in transmission and distribution, though full did not materialize. Following the collapse of the proposed asset sale to in 2010, NB Power pursued internal efficiencies but implemented no major structural shifts until 2022, when the board announced a corporate transformation initiative amid escalating and pressures. This included the departure of President and CEO Keith Cronkhite on July 4, 2022, appointment of Lori Clark as acting CEO, and engagement of PricewaterhouseCoopers for a strategic review to optimize costs, , and pathways, emphasizing cultural transformation for better customer focus and operational agility. In 2024, further amendments to the Electricity Act enabled NB Power to form strategic partnerships with external entities for managing existing and assets, alongside accessing alternative funding sources, as part of broader regulatory reforms to support clean energy adoption, reduce operational risks, and lower costs through modernization for technologies like microgrids. These changes, introduced in May 2024 under the provincial clean energy strategy, allow greater flexibility in without altering the core crown corporation framework.

Valuation, Debt Management, and Financial Constraints

NB Power's net debt stood at $5,775 million as of March 31, 2025, comprising long-term debt of $5,396 million and short-term indebtedness of $954 million, net of sinking funds and cash equivalents. This represented a slight increase from $5,347 million the prior year, driven by capital expenditures on aging and refurbishments, despite efforts to stabilize borrowings through provincial guarantees leveraging the province's Aa1 from Moody's. Equity attributable to shareholders was $484 million at that date, yielding a net debt-to-capital ratio of 92 percent, an incremental improvement from 93 percent in but still far exceeding the legislated target of 80 percent debt to 20 percent equity mandated by the Electricity Act for fiscal sustainability by March 31, 2029. Debt management at NB Power relies on a combination of regulated rate adjustments, operational cost controls, and deferred regulatory accounts to generate for principal repayments and equity building. The utility has pursued multi-year rate applications, securing approvals for 9.14 percent increases in both 2024 and 2025 to offset rising interest expenses and fund service, while employing rate-smoothing mechanisms to mitigate immediate affordability shocks—such as deferring portions of a projected 14.4 percent hike into future periods. Additional strategies include seeking alternative financing for major projects, such as strategic partnerships for hydroelectric refurbishments at Mactaquac Generating Station, and optimizing export sales to markets to bolster revenues amid variable hydroelectric output and fuel costs. However, progress toward the equity target has been uneven, with annual debt reductions averaging below the required $65 million needed to meet deadlines, hampered by unbudgeted outages at facilities like and events costing $31 million in restoration in late 2023. Financial constraints stem primarily from the elevated debt burden relative to peers, where NB Power's 92-94 percent over the past decade exceeds North American utility averages of 75-80 percent and features the weakest interest coverage among comparable entities, averaging 0.74 times over 2010-2019—insufficient to cover even one year of payments in multiple fiscal periods. This structure amplifies vulnerability to interest rate fluctuations and limits access to unsubsidized capital markets, necessitating continued reliance on provincial borrowing despite the province's strong ratings, which Moody's has flagged as a growing concern for potential spillover risks. Constraints manifest in deferred maintenance risks, as high leverage curtails investments in grid reliability and capacity additions—exacerbated by forecasts of supply shortfalls within three years absent new natural gas-fired generation estimated at over $1 billion. Ongoing rate pressures, with a further 4.75 percent increase sought for 2026, underscore the tension between debt servicing and customer affordability, prompting a provincial review in 2025 to assess options without immediate commitments.
Fiscal Year Ended March 31Net Debt ($ millions)Equity ($ millions)Net Debt-to-Capital Ratio (%)
20235,40633494
20245,34740693
20255,77548492
The table illustrates modest ratio improvement amid rising absolute debt, reflecting incremental equity growth from but insufficient to offset capital demands.

Leadership and Workforce

Executive Leadership and Board Composition

The executive leadership of Power Corporation (NB Power), a provincial Crown corporation, is led by President and Lori , who was officially appointed on March 20, 2023, following an acting role since July 4, 2022; she is the first woman to hold the position and also serves as Chief Nuclear Officer. , who joined NB Power in 1990, previously held roles such as Controller and Vice President of Regulatory Affairs, and holds a BBA from the , CPA designation, and executive education from MIT and Wharton. The senior management team comprises experienced professionals primarily from within the organization or the energy sector, overseeing key functions including finance, operations, customer service, and nuclear operations. As of October 2025, the is Justin Urquhart, appointed on , 2025, succeeding Darren Murphy; Urquhart previously served as of Finance at NB Power and focuses on fiscal sustainability and . Other key executives include of Operations Nicole Poirier (appointed June 2023, with over 34 years at NB Power overseeing and transmission), of Business Development and Brad Coady (appointed June 2023), Jean Marc Landry (appointed July 2021), of People and Culture Suzanne Desrosiers (appointed February 2021), and Site for Steve Bagshaw (appointed September 2023, with prior experience in nuclear refurbishments). These leaders report to the CEO and manage day-to-day operations under board oversight. NB Power's , responsible for administering the corporation's affairs on a commercial basis while considering provincial government policy directions, consists of nine members as of 2025, including the CEO as an ex-officio director. The board is appointed by the Lieutenant-Governor in Council on the advice of the provincial government, reflecting its status as a accountable to taxpayers. Chairman Andrew MacGillivray, a retired President and CEO of Foods with a BBA from and MBA from , provides strategic guidance.
MemberBackground
Alain BosséPresident and COO of Groupe Inc., with 35 years in the family-owned manufacturing firm.
Chantal CormierPresident and CEO of McCram Inc., holding BBA and MBA from .
Paul McCoy, P.E.Engineering consultant and co-founder of Trans-Elect, with BS in from .
Scott Northard, P.E.President of Due North Energy Consulting, BS in from University of Wisconsin.
Patrick Oland of , BComm from and MBA from .
Michelyne PaulinCPA with over 40 years of experience, BBA from .
Wayne PowerRetired executive from , BSc in from and MBA from City University.
The board's composition emphasizes expertise in energy, finance, engineering, and business leadership, drawn largely from , to balance commercial objectives with public policy mandates such as reliability and affordability. The President and CEO reports directly to the board, which holds the executive accountable for operational performance.

Employee Relations, Unions, and Operational Staffing

The (IBEW) Local 37 serves as the primary bargaining agent for NB Power employees, representing approximately 81% of the workforce across operational roles in , transmission, distribution, and . This union, which covers over 2,500 members province-wide in utility and related sectors, negotiates collective agreements that govern wages, benefits, working conditions, and dispute resolution mechanisms. NB Power's total workforce exceeds 2,600 employees, primarily New Brunswickers focused on delivering reliable services through specialized staffing in hydroelectric, thermal, and nuclear facilities. Collective bargaining processes have yielded multi-year agreements tailored to operational needs, such as the National Maintenance Agreement (NMA) with NB Power effective from 2023 to 2026, which addresses grievance procedures, training funds, and labor-management panels for prompt resolution of disputes. Separate provisions apply to nuclear operations at Point Lepreau, with a dedicated from 2020 to 2023 emphasizing shift assignments, negotiating team participation, and protocols during refurbishments. These contracts include mechanisms for union representatives to engage in negotiations without exceeding defined limits on personnel, ensuring continuity in staffing. Employee relations emphasize collaboration on and reliability, though isolated arbitrations highlight tensions over ; for instance, in 2023, an arbitrator upheld the termination of a long-service foreman for a serious violation despite his clean record, prioritizing operational hazards in work. Conversely, a 2024 ruling overturned the dismissal of a worker accused of , deeming termination disproportionate absent progressive . Operational staffing has faced pressures from aging and skill requirements, prompting initiatives like early incentives to transition expertise in high-risk areas such as nuclear refurbishment and grid maintenance. However, a June 2025 provincial auditor's review found that despite these packages, NB Power's overall headcount increased beyond pre-incentive levels, raising questions about efficiency in workforce planning amid rising operational demands. No large-scale strikes have disrupted NB Power operations in recent years, reflecting relatively stable under New Brunswick's public-sector framework, which mandates for binding settlements and imposes notice requirements for potential job actions. Union involvement extends to partnerships, supporting programs that maintain staffing competency in a province-dependent energy sector.

Operations

Electricity Generation Portfolio

NB Power maintains an electricity generation portfolio centered on owned facilities with a total installed net capacity of 3,799 MW, encompassing nuclear, hydroelectric, , and combustion turbine assets. This mix supports baseload, intermediate, and peaking needs, with nuclear and hydro providing lower-cost, lower-emission output relative to sources, though the latter ensure dispatchable reliability amid variable hydro flows and nuclear outages. The portfolio excludes approximately 600 MW of contracted capacity from independent power producers, primarily and , which supplements NB Power's supply but operates under power purchase agreements rather than direct ownership. The nuclear component, comprising 660 MW from the single-unit Point Lepreau Generating Station—a CANDU-6 pressurized heavy-water reactor commissioned in 1983—delivers baseload power equivalent to about one-third of provincial demand under optimal conditions. Refurbished between 2011 and 2020 at a cost exceeding initial estimates, it achieved a capacity factor above 90% in recent operations but has faced delays and reliability challenges affecting overall portfolio output. Hydroelectric facilities total 889 MW across roughly a dozen run-of-river and storage stations on the Saint John River and other waterways, with the Mactaquac Generating Station contributing 672 MW as the largest site; these assets generated 3.14 million MWh in a recent fiscal year, influenced by precipitation variability. Thermal generation, at 1,723 MW, relies on fossil fuels for flexible dispatch, including the coal-fired Belledune station (approximately 665 MW , though net output varies with fuel and efficiency), oil- and gas-capable Coleson Cove (around 670 MW), and the natural gas-fired Bayside combined-cycle plant (285 MW). These facilities produced 2.57 million MWh in recent data, serving as backup during hydro droughts or nuclear maintenance, but incur higher fuel costs—nuclear uranium being the second-lowest-cost input after hydro. Combustion turbines, totaling 525 MW, function as diesel- or gas-peaking units for short-term demand spikes or grid stability. Efforts to transition Belledune from , including co-firing trials since 2017, reflect regulatory pressures to reduce emissions, though full conversion remains undecided as of 2025.
Fuel TypeInstalled Capacity (MW)Approximate Share
Nuclear66017%
Hydroelectric88923%
(fossil)1,72345%
Turbine52514%
Total3,797100%
This capacity distribution underscores a heavy reliance on thermal assets for reliability, despite their environmental and cost drawbacks, with nuclear and hydro comprising the core low-marginal-cost base; annual output shares reflect operational factors, with nuclear at around 4.82 million MWh in baseline years. In July 2025, NB Power announced the Renewable Integration and Grid Security project, its first owned capacity expansion in over 20 years, aimed at adding firm renewable-linked to address emerging risks, though details on scale and timeline remain preliminary.

Transmission, Distribution, and Grid Infrastructure

NB Power's transmission network comprises approximately 6,900 kilometres of high-voltage lines operating at levels ranging from 69 kV to 345 kV, facilitating the bulk transfer of electricity from generating stations to distribution substations across New Brunswick. The system includes 48 industrial substations, 49 terminal, plant switchyards, and switching stations, along with 40 microwave and mobile radio towers for communication and control. The Transmission and System Operator division oversees the design, construction, maintenance, and operation of these facilities, ensuring reliability and compliance with voltage standards maintained between 0.95 and 1.05 per unit for normal operations. The distribution infrastructure consists of about 21,800 kilometres of lines that step down voltage from transmission levels to end-user standards, such as 7,200/12,470 V for many services and ultimately 120/240 V for residential customers. Distribution feeds into numerous substations, including key urban ones like those in and Saint John, supporting over 400,000 customers province-wide. Recent enhancements include the Fredericton South Reliability Project, which adds transmission capacity via dual lines connecting to three distribution substations, and the Saint John Corridor Project featuring a new 32-kilometre line from Coleson Cove to mitigate local constraints. NB Power's grid interconnects with neighboring systems through 15 ties, enabling an import capacity of 2,378 MW and export capacity exceeding 2,000 MW, which supports energy trading and reliability during shortages. Ongoing modernization efforts include deploying over 300,000 advanced metering infrastructure (AMI) devices by August 2025 to enhance , outage detection, and customer insights, alongside projects like a at the substation for voltage stability. A proposed $180 million upgrade in southern aims to bolster transmission capacity amid rising demand, while interprovincial initiatives, such as a 345 kV line with , seek to double cross-border flows with federal backing. These investments address aging assets and integrate renewables, though they contend with environmental assessments and fiscal pressures.

Fuel Sourcing and Ancillary Activities (e.g., )

NB Power's generating stations, including the Belledune Generating Station, primarily rely on as a source, supplemented by and at facilities such as Coleson Cove and Bayside. Coal consumption supports approximately 27-36% of the province's in recent years, though this share is declining amid federal mandates to phase out unabated coal-fired power by 2030. Historically, NB Power engaged in through its NB Coal, operating a mine in Minto, , from 1986 until its closure in September 2009. The Minto mine produced around 150,000 tons of annually, primarily to supply the nearby Grand Lake Generating Station, but operations ceased due to the uneconomic nature of local extraction under tightening environmental regulations and the station's decommissioning. Currently, NB Power does not own or operate any mines, sourcing thermal through international procurement, mainly from suppliers in the United States and , including Glencore-operated mines in . In response to phase-out requirements, NB Power initiated testing of alternative fuels at Belledune in March 2024, co-firing wood pellets to assess feasibility for full conversion, with further trials in November 2024 to refine capital estimates. and diesel fuels for peaker plants are procured via maritime imports, while supplies leverage regional pipelines, though specific supplier contracts remain competitively bid and not publicly detailed in tenders. Ancillary activities beyond mining are limited to fuel handling and storage at port-adjacent sites like Belledune, facilitating direct ship unloading to minimize logistics costs. for Point Lepreau, , is sourced internationally under long-term contracts, independent of domestic mining efforts.

Financial Performance and Economics

NB Power's primary revenue streams derive from electricity sales, encompassing both in-province domestic customers and out-of-province exports. For the fiscal year ended March 31, 2024, total revenue reached $2,968 million, with in-province sales accounting for $1,606 million (54%), predominantly from residential customers ($761 million), industrial users ($380 million), and general service ($323 million). Out-of-province sales contributed $1,268 million (43%), largely through long-term contracts to the ($906 million) and ($137 million), supplemented by short-term trades and credits. Miscellaneous revenue, including ancillary services and non-electricity sources, added $94 million (3%). This structure reflects NB Power's reliance on export markets to offset domestic rate constraints, though export volumes fluctuate with regional demand and pricing. Costs and expenses for the same period totaled $2,614 million before charges, dominated by fuel and purchased power at $1,589 million (61%), reflecting dependence on nuclear, hydro, and generation amid variable input prices. Operations, , and administration costs were $622 million (24%), and amortization $354 million (13%), and taxes $49 million (2%), with costs adding $309 million due to substantial servicing. These expenditures are influenced by generation portfolio efficiency, such as Point Lepreau Nuclear Generating Station's improving to 87.1% in 2024 from 56.6% in 2023, which reduced fuel reliance. Storm-related restoration costs, totaling $31 million in 2024, exemplify operational vulnerabilities exacerbating expense pressures. Profitability trends have been volatile, shifting from a net profit of $80 million in fiscal 2022 to a $43 million loss in 2023, before recovering to $7 million in 2024 and $23 million in 2025. The 2023 downturn stemmed from a 100% surge in fuel and purchased power costs to $1,968 million, driven by global energy price spikes, supply chain disruptions, and nuclear outages, outpacing a 32% revenue increase to $2,911 million. Recovery in 2024 resulted from a $395 million drop in fuel expenses and higher sales volumes, yielding a $41 million revenue gain despite regulatory balance adjustments eroding earnings by $114 million. By 2025, revenue dipped to $2,619 million amid lower exports, but controlled expenses ($2,627 million total) and efficiency gains supported modest profitability. Overall, trends underscore sensitivity to fuel volatility and asset performance, with net debt rising to $5,347 million by 2024 amid capital investments.
Fiscal Year Ended March 31Total Revenue ($M)Key Expenses: Fuel/Purchased ($M)Net Income/Loss ($M)
20222,198983+80
20232,9111,968-43
20242,9681,589+7
20252,6191,500+23

Debt Burden, Credit Ratings, and Fiscal Sustainability

As of March 31, 2025, NB Power's net debt stood at $5.775 billion, reflecting a $428 million increase from $5.347 billion the previous fiscal year, driven primarily by an extended outage at the Point Lepreau Nuclear Generating Station and elevated capital expenditures. By June 30, 2025, net debt had decreased slightly to $5.677 billion following positive operating earnings. Total debt, including long-term and short-term components, reached $6.350 billion at fiscal year-end 2025, with long-term debt comprising $5.396 billion. This accumulation stems from historical investments in infrastructure, including nuclear refurbishments, alongside ongoing operational pressures such as fuel costs and regulatory requirements. NB Power's remains elevated, with net debt constituting 92% of its as of March 31, 2025, deteriorating to 93% by June 30, 2025. The Act mandates a minimum 80% debt-to-20% equity structure, but the provincial removed the 2029 target date in May 2025 amid rate pressure concerns, prompting criticism from bond rating analysts that this delays deleveraging and heightens reliance on customer-funded rate hikes. Compared to North American peers, NB Power's exceeds the typical 75-80% debt benchmark and is the highest among Canadian counterparts at around 94% in recent assessments. Equity stood at $484 million as of March 31, 2025, supported by of $532 million but constrained by accumulated losses and limited internal generation. Credit ratings for NB Power are closely linked to its status as a provincial Crown corporation, with agencies evaluating it alongside New Brunswick's sovereign ratings due to implicit support mechanisms. Moody's affirmed the province's Aa1 rating with a stable outlook in May 2024 but expressed concern over NB Power's deteriorating financial position, including rising debt, as a potential drag on provincial finances. S&P Global Ratings affirmed the province's A+ long-term rating with a stable outlook in April 2025, viewing NB Power as largely self-supporting with capacity to meet debt obligations, though contingent liabilities from the utility factor into provincial assessments. DBRS Morningstar confirmed the province's A (high) rating, noting NB Power's debt as a key vulnerability but offset by the government's demonstrated willingness to provide backing. NB Power pays the province an annual fee of 1% on outstanding debt for portfolio management, underscoring the intertwined fiscal risks. Fiscal sustainability faces strain from weak interest coverage, with a 10-year average of 0.74—the lowest among peer Canadian utilities—and a fiscal 2025 ratio of -0.03, indicating earnings insufficient to cover interest expenses amid high leverage and volatile revenues. The utility's $5.7 billion net debt equates to roughly $14,500 per provincial household, fueling debates over potential bailouts or debt forgiveness to avert further rate escalation, projected to continue through rate applications averaging 9.25% for 2025-2026. A provincial review initiated in April 2025 targets fiscal sustainability, governance, and rate impacts, recognizing limited equity growth options without external intervention. While provincial balance sheet strength provides a backstop, sustained high debt risks credit pressures and higher borrowing costs unless offset by cost controls, asset sales, or efficiency gains.

Rate Regulation, Customer Rates, and Economic Impacts

NB Power's electricity rates are regulated by the Energy and Utilities Board (NBEUB), an independent body established under the Electricity Act to ensure rates are just, reasonable, and reflective of the utility's costs while promoting stability. The NBEUB reviews NB Power's filings, including schedules of charges, and holds public proceedings to assess applications, balancing utility financial needs against customer affordability. The primary mechanism for rate adjustments is the General Rate Application (GRA), where NB Power submits detailed forecasts of revenues, expenses, capital investments, and service requirements for approval. In these applications, rates are designed to cover operational costs, infrastructure maintenance, and returns on invested capital, with the NBEUB often approving multi-year plans to minimize frequent changes. For example, a December 2023 GRA sought a 9.25% average annual increase across customer classes for fiscal years 2024/25 and 2025/26, which the NBEUB largely approved in March 2025 with minor modifications to service charges. Customer rates have risen sharply in recent years following decades of suppressed increases that contributed to NB Power's accumulated debt. Residential rates, effective April 1, 2025, reflect a 9.7% increase from the prior year, positioning them as among the lowest in despite the hike, with basic charges at approximately $28.50 monthly plus rates around 10.5¢/kWh for the first 100 kWh in winter. Industrial and commercial rates, often interruptible, have seen similar escalations; historical interruptible prices averaged $42–$50/MWh from 2016–2019 but have climbed amid broader cost pressures. On October 1, 2025, NB Power filed a new GRA requesting a 4.75% across-the-board increase for 2026/27 to address ongoing fiscal shortfalls.
Fiscal YearAverage Increase ApprovedResidential Impact
2024/259.25%9.8%
2025/269.25%9.7% (effective April 1, 2025)
These rate hikes have imposed measurable economic burdens, particularly on New Brunswick's export-dependent industries, where electricity costs now exceed average by over 14% for large industrials, eroding competitiveness and risking job losses. Rising residential bills exacerbate household cost-of-living pressures, while business increases—compounded by NB Power's debt servicing—threaten broader growth, tax revenues, and energy-intensive sectors like and . In response, the provincial government launched a comprehensive review of NB Power in October 2025 to prioritize affordability, reliability, and long-term sustainability amid slowing economic growth.

Controversies and Criticisms

Nuclear Refurbishment Overruns and Reliability Issues

The , New Brunswick's sole nuclear facility, underwent a major refurbishment project beginning in April 2008, initially projected to last two years and cost $1.4 billion. The project aimed to extend the plant's operational life by replacing key components, including the reactor's feeder pipes and steam generators. However, it faced significant delays and cost escalations, ultimately taking 54 months and exceeding the budget by approximately $1 billion, with total costs reaching around $2.4 billion by completion in October 2012. These overruns stemmed from technical challenges, such as difficulties in replacing calandria tubes and steam generators, as well as scope changes and supply chain issues, leading NB Power to pursue legal action against (AECL) for $1 billion in alleged mismanagement. The extended downtime forced NB Power to import more expensive power from neighboring grids, contributing to higher electricity rates for customers and prompting criticism from provincial auditors for inadequate project oversight. Post-refurbishment, the station has experienced persistent reliability problems, including unplanned outages and low capacity factors, ranking it among North America's worst-performing nuclear plants as of 2024. A major electrical fault on December 14, 2022, caused a trip and subsequent power loss, exacerbating supply reliability concerns. In 2024, a planned 98-day maintenance outage starting April 6 extended to 248 days due to an unforeseen equipment issue, delaying return to service until December 16. Further complications arose in early 2025 when a large cooling fan failed, sidelining the plant until repairs were completed on March 24, with these incidents accounting for significant portions of NB Power's replacement power costs passed to ratepayers via surcharges. Critics, including energy analysts, have attributed these issues to underlying design flaws not fully addressed in the initial refurbishment, potentially necessitating a second major overhaul around 2041 at additional billions in cost. NB Power has acknowledged the financial strain, exploring mitigation options while maintaining the plant's role in the province's despite its history of underperformance.

Failed Hydro-Québec Acquisition Attempt

In October 2009, amid Power's mounting debt—exacerbated by cost overruns at the Point Lepreau nuclear generating station— Premier Shawn Graham and Premier signed a for to acquire most of NB Power's non-nuclear generating assets, including hydroelectric and thermal facilities, for approximately $4.75 billion. Under the terms, NB Power would retain its distribution system and the Point Lepreau nuclear plant, while committed to supplying with a fixed-price block of 700 megawatts of power annually for up to 40 years to help stabilize provincial electricity rates, which had risen sharply due to NB Power's financial pressures. The province would also receive payments toward debt relief, with the deal requiring legislative approval in both provinces and federal review for interprovincial trade implications. The proposal faced immediate and intense opposition in , including widespread public protests, union campaigns, and criticism from opposition parties and federal Conservative Leader , who highlighted risks to energy sovereignty and potential job losses estimated in the thousands from plant closures or relocations. Critics argued the arrangement would cede control of key infrastructure to , potentially enabling to prioritize exports to the U.S. over New Brunswick's needs, while long-term rate protections might expire unfavorably; proponents countered that it would offload $4.7 billion in provincial guarantees on NB Power's debt and prevent further rate hikes. In January 2010, the agreement was revised to a $3.2 billion price for the generating assets and a reduced 670-megawatt power block, amid ongoing revealing higher-than-expected liabilities. The deal collapsed on March 24, 2010, after identified unanticipated s and costs during —such as , aging repairs, and regulatory uncertainties—totaling hundreds of millions more than initially projected, which the parties could not resolve through allocation negotiations. Charest cited these "new elements" as insurmountable without further concessions from , while Graham emphasized the province's unwillingness to assume additional fiscal burdens. The failure preserved NB Power's integrated structure but intensified scrutiny of its debt and management, contributing to Graham's electoral defeat later that year; , meanwhile, redirected focus to U.S. export opportunities without the acquisition.

Allegations of Mismanagement and Debt Accumulation

NB Power's debt has grown significantly over decades, reaching $4.9 billion by 2020—an increase of $2 billion since 2002—driven by large capital expenditures and forecasting inaccuracies that understated net earnings shortfalls by approximately $50 million annually and overstated fuel and purchased power savings by $87 million per year. The utility's stood at 94 percent in 2020, the highest among comparable entities and far exceeding the legislated target of 80/20 by 2027, which required annual debt reductions of $65 million but achieved only $20 million since 2013. Critics, including the of , have attributed this accumulation to management failures in prioritizing debt reduction and producing overly optimistic expense forecasts that misled regulators during rate applications. By late 2024, the had deteriorated further to 94/6 from 87/13, with total surpassing $5 billion, including $2 billion linked to new , raising ongoing concerns about the utility's self-sustainability without provincial backing. The highlighted NB Power's persistent non-implementation of 2020 recommendations, such as establishing a defined and refining forecasts for variables like fuel prices and weather impacts, which have contributed to unaddressed operating challenges and profitability deficits. Opposition figures have alleged that historical political interference maintained artificially low rates, preventing cost recovery and forcing financing for essential investments, exacerbating the imbalance where growth has outpaced adjustments. In October 2025, CEO Lori Clark acknowledged the debt had reached $5.7 billion and projected continued expansion alongside rate hikes of 4.75 percent for 2026 and 6.5 percent for 2027–2028, primarily to address aging assets like the Mactaquac Dam refurbishment, but without specifying measures to reverse the trend beyond gradual rate catching-up. Bond rating agencies have warned that proposals to abandon the 80/20 debt target—floated by the provincial government in March 2025—carry risks of credit downgrades and higher borrowing costs, underscoring allegations that lax fiscal discipline under prior and current management has prioritized short-term rate suppression over long-term viability. These issues have prompted calls for broader inquiries, with the utility reporting a $43 million net loss in the prior year amid stalled progress on debt retirement surcharges imposed on customers.

Supply Reliability Risks and Capacity Shortfalls

NB Power has forecasted a potential capacity shortfall beginning in 2028, driven by electricity demand growth exceeding projections outlined in its 2023 Integrated Resource Plan (IRP). The utility's July 14, 2025, announcement of a new generation capacity expansion project highlighted that accelerated demand, fueled by unprecedented population growth in , has outpaced earlier estimates, necessitating additional resources to maintain a 20% reserve margin for reliability. On October 11, 2025, NB Power CEO Lori Clark testified before a legislative committee, warning that without substantial investments in generation and maintenance, the province risks electricity shortages within three years, compromising system reliability. This assessment aligns with earlier IRP analyses, such as the 2020 plan indicating shortfalls potentially starting in 2027, exacerbated by challenges in sustaining aging assets amid rising needs. Peak demand periods, particularly cold winter mornings exceeding 2,500 MW, strain the grid, often requiring reliance on higher-cost peaking units with limited flexibility. Aging , including deferred maintenance on generating stations and transmission lines, heightens outage risks and concerns, as noted in provincial reviews and regulatory decisions emphasizing the need for upgrades to avert failures. NB Power's dependence on interconnections for imports, with a capacity of 2,378 MW, provides balancing options but introduces vulnerabilities to regional supply tightness or transmission constraints, particularly as neighboring grids face similar pressures. While the maintains over 4,300 MW of total installed capacity, effective firm capacity is reduced by factors like hydroelectric variability and periodic nuclear outages, underscoring the thin margins during high-demand scenarios.

Environmental Transition Policies and Cost Implications

NB Power has committed to achieving a net-zero electricity supply by 2035, building on its current portfolio where approximately 80% of generation is from non-emitting sources such as hydroelectric, nuclear, and limited renewables. This target aligns with provincial and federal climate objectives, including New Brunswick's Climate Change Action Plan, which emphasizes decarbonization through fuel switching, efficiency improvements, and low-emission technology adoption. The company's 2023 Integrated Resource Plan (IRP) outlines 16 potential pathways to net-zero, incorporating scenarios for expanded renewables, conversion at the Belledune Generating Station, nuclear refurbishment at Point Lepreau, and potential imports or new low-emission baseload capacity to address intermittency and reliability. Key policies focus on phasing out unabated coal-fired generation by 2030, in compliance with federal regulations under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. For the Belledune station, NB Power has selected black pellet biomass as a cost-effective replacement for coal, enabling continued baseload operation while reducing emissions by an estimated 32 megatonnes cumulatively through 2045 compared to ongoing coal use. Complementary measures include soliciting proposals for up to 200 MW of renewable capacity through competitive streams prioritizing net-zero contributions, such as wind and solar, with recent execution of four wind power purchase agreements in 2025. Provincial targets support this by aiming to increase solar capacity nearly fivefold to 200 MW by 2035 via grid-scale additions. These transitions carry substantial cost implications, primarily through capital investments and elevated operating expenses passed to ratepayers via regulated increases. The 2023 IRP identifies pathway-dependent expenditures, with one scenario involving $270–310 million for new transmission infrastructure and additional hydroelectric imports from to replace capacity. NB Power's 2024–2025 General Rate Application attributes part of a requested 9.25% average annual rate hike to refurbishment and transition-related works, including upgrades and supply modernization essential for net-zero compliance. Economic modeling of indicates modest present-value GDP reductions in , on the order of small percentages, due to higher generation costs from alternatives lacking coal's dispatchable reliability without equivalent carbon pricing offsets. Critics, including analyses from the , contend that aggressive decarbonization mandates exacerbate volatility and economic contraction by prioritizing intermittent renewables over proven baseload options, potentially straining fiscal amid existing burdens. Despite these, NB Power emphasizes cost-effective pathways in its IRP, such as biomass retrofits over pricier builds, to balance emissions reductions with affordability.

Strategic Outlook and Provincial Impact

Decarbonization Commitments and Technology Shifts

NB Power has committed to achieving net-zero from its by 2035, as detailed in its 2023 Integrated Resource Plan, which outlines 16 potential pathways to decarbonize the grid while maintaining reliability and affordability. This target supports New Brunswick's broader economy-wide net-zero goal by 2050 under the Net-Zero Emissions Accountability Act, with the utility's grid already operating at approximately 80% carbon-free capacity through hydroelectric, nuclear, and other low-emission sources, representing over 70% reduction in emissions from 2005 levels. The plan emphasizes least-cost strategies balancing economic sustainability, risk mitigation, and environmental outcomes, prioritizing baseload stability over intermittent renewables alone. To meet these commitments, NB Power plans to phase out unabated coal-fired generation by 2030 in alignment with federal regulations, including conversion of the Belledune Generating Station to fuel using wood pellets to sustain operations and avoid premature closure. All remaining plants are targeted for elimination by 2035, shifting reliance to expanded nuclear capacity, with 600 MW of small modular reactors (SMRs) planned at to double carbon-free baseload output. The province has selected vendors like for SMR development, though procurement flexibility allows sourcing from multiple suppliers if domestic timelines lag. Renewable integration forms a complementary shift, with recent advancements including four purchase agreements signed in May 2025 for low-cost projects and the July 2025 announcement of the 400 MW Renewable Integration and Grid Security (RIGS) initiative, developed with PROENERGY to enhance grid stability amid variable and solar inputs. co-firing and dedicated facilities will provide dispatchable low-emission power, central to bridging gaps in intermittent renewables while federal funding exceeding $1 billion supports clean electricity expansions as of December 2024. These shifts prioritize nuclear and for reliability, given renewables' limitations in providing firm capacity without substantial storage or overbuild, as evidenced by grid modernization efforts in the 2023-2035 Strategic Plan.

Capacity Expansion Initiatives and Future Projects

NB Power's capacity expansion initiatives are primarily guided by its 2023 Integrated Resource Plan (IRP), which outlines multiple pathways to achieve a net-zero system by 2035 through a combination of renewable additions, storage, nuclear advancements, and firm dispatchable capacity to meet growing and replace retiring assets. The IRP targets include up to 300 MW of new by 2026/27, 50 MW of battery storage, refurbishment of the 668 MW Mactaquac hydroelectric generating station by 2032/33, and initial deployment of 150 MW from small modular reactors (SMRs) by 2034/35, alongside by 2030. These efforts address projected growth from , population increases, and industrial loads, while prioritizing grid reliability amid variable renewables. A cornerstone firm capacity project is the Renewable Integration and Grid Security (RIGS) initiative, announced on July 14, 2025, marking NB Power's first major generation expansion in over two decades. This 400 MW peaking facility, featuring dual-fuel combustion turbines and synchronous condensers, will be developed, built, owned, and operated by PROENERGY in partnership with NB Power and the North Shore Mi’kmaq Tribal Council. Located on NB Power-owned land near Route 940 in Midgic and Centre Village, southeastern , it aims to mitigate capacity shortfalls expected by 2028, enhance grid stability for renewable integration, and displace higher-emission units during peaks or extreme weather. An has been filed, with construction timelines aligned to operational needs by late 2020s. Renewable expansions emphasize wind and solar to support decarbonization. On May 7, 2025, NB Power signed four wind power purchase agreements totaling 452 MW, involving Indigenous partnerships: Salmon River (200 MW by Wolastoqey Resource Developments and Natural Forces), Paqt'smawei Sipu (100 MW by L’nui Menikuk First Nation, Mi’gmaq United, and Natural Forces), Astuwicuwon (92 MW by Sitansisk First Nation and Eolectric), and Papoqji'jg (60 MW by Pabineau First Nation and ABO Energy). These projects, distributed across New Brunswick, are slated for service by 2027/2028, contributing to the IRP's near-term wind targets and economic benefits via local jobs. Complementing this, NB Power issued requests for expressions of interest (REOIs) for up to 400 MW of solar—200 MW via a net-zero pathway (operational 2029–2030) and 200 MW via a large-scale accelerator (2027–2028, projects over 100 MW each)—to scale photovoltaic capacity toward provincial goals of 200 MW additional grid-scale solar by 2035. Future nuclear projects center on SMRs at the Point Lepreau site, with NB Power partnering with ARC Clean Technology Canada on the ARC-100 design for an initial 100 MW sodium-cooled fast reactor, potentially scaling to 150 MW by 2034/35 per IRP scenarios. Provincial investments exceeding $30 million support commercialization, amid collaborations with Ontario Power Generation on SMR deployment, though timelines face uncertainty with the first unit possibly delayed beyond the late 2030s due to regulatory and supply chain hurdles. The Mactaquac refurbishment, ongoing through 2032/33, will restore and potentially enhance 668 MW of hydroelectric capacity, ensuring baseload renewables without new dams. These initiatives balance reliability, cost, and emissions reductions, though execution risks include supply chain delays and integration challenges for intermittent sources.

Broader Economic Role, Energy Security, and Policy Debates

NB Power serves as a cornerstone of New Brunswick's economy, generating, transmitting, and distributing electricity to nearly all residential, commercial, and industrial customers in the province through 13 generation facilities and approximately 6,900 km of transmission lines. This infrastructure supports key sectors such as , , and , where reliable power underpins operations, but escalating rates— including a 9.7% hike for residential users effective April 1, 2025, and steeper increases for businesses—have strained competitiveness and household budgets, prompting criticism that high costs hinder broader economic vitality. Industrial stakeholders, including major employers like , have highlighted projected 20-25% rate escalations over two years as a threat to investment and job retention. In terms of , NB Power grapples with supply vulnerabilities stemming from reliance on aging assets like the Point Lepreau nuclear station and intermittent imports, exacerbated by provincial commitments to phase out coal by 2030 while pursuing net-zero emissions. Recent initiatives prioritize nuclear refurbishments, with seeking technical support from in October 2025 to restore consistent output at Point Lepreau, underscoring a tilt toward baseload nuclear capacity to mitigate blackout risks over faster renewable rollouts. Government officials have explicitly favored rapid nuclear expansion for security reasons, even if it delays ancillary economic projects, amid debates over balancing debt reduction with resilience. Policy debates surrounding NB Power intensify around affordability, ownership structure, and the optimal , fueled by the utility's substantial —estimated to include stranded assets not being systematically retired—and recurrent rate shocks that dominated legislative discussions in 2025. A provincial review launched in 2025 seeks to scrutinize operations for cost controls and reliability enhancements, though public engagement has been limited, raising questions about transparency and potential reforms like partial . Contention also arises over a proposed large-scale plant in Tantramar, defended by NB Power executives as essential for peaking power but challenged by energy analysts favoring battery storage as a cheaper, lower-emission alternative, with estimates indicating batteries could suffice without the $500 million-plus fossil investment. These disputes reflect broader tensions between short-term reliability imperatives and long-term decarbonization mandates, with critics arguing that unchecked and fossil dependencies undermine fiscal prudence absent rigorous cost-benefit scrutiny.

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  164. https://www.ctvnews.ca/atlantic/new-brunswick/article/nb-gets-support-from-ontario-to-repair-and-improve-operations-at-point-lepreau-nuclear-facility/
  165. https://www.cbc.ca/news/canada/new-brunswick/nb-power-review-low-public-interest-1.7631557
  166. https://nbmediacoop.org/2025/10/21/nb-power-execs-grilled-at-committee-over-plans-for-gas-burning-plant/
  167. https://uk.news.yahoo.com/2-energy-experts-n-b-192055055.html
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