Tom Adams, Executive Director
May 7, 2002
Review of Financial Fitness, Institutional Certainty, and Investment Risk
New Brunswick Public Utilities Board
Concerning a Proposal to Refurbish the Point Lepreau Nuclear Generating Station
New Brunswick’s electricity system is financially unfit to undertake the proposed Point Lepreau retubing effort. New Brunswick’s electricity system faces a combination of negative factors. NB Power’s debt is unfavorable and its operating costs, already the highest of the Canadian utilities for which comparable data are available, are trending to become more unfavorable. These factors combined with persistent reported negative net income, unreported costs, and slow progress in debt reduction make NB Power the weakest utility in Canada in financial terms. The utility suffers from a lack of policy direction and only has an acting CEO yet is pursuing an aggressive capital spending strategy. NB Power is on track to have the highest relative debt in Canada, a factor that is likely to increase rates. If current trends continue, New Brunswick’s power system is likely to face more significant financial challenges in future years than those it now faces. Should current trends continue, a significant injection of capital from some level of government may be required to allow the power system to remain functional.
NB Power’s investment strategy is risky.
Some alternative low-carbon energy alternatives to nuclear investments are suggested and some similarities between NB Power’s application and Ontario’s recent experience with monopoly utility central are identified.
NB Power’s Unsustainable Liabilities and High Operating Cost Exposure in Context
New Brunswick’s electricity debt is already excessive and will increase substantially under its proposed capital program.
Utility liabilities, including debt and other obligations, contribute to current and future rates. Excessive debt levels can reduce a utility’s financial flexibility. Operating costs contribute to current rates. Excessive operating costs can also reduce a utility’s financial flexibility.
It is financially appropriate for utilities providing services that are to some extent necessarily capital intensive to incur debt. One justification for utility debt is to acquire assets that have low operating costs. A common example is hydro-electric generating investments. Although their capital costs are high, their running costs are typically relatively low.
Excess utility liabilities, particularly when combined with high operating costs, are damaging to the public interest. Relative to all other utilities in Canada, NB Power has put itself in a double jeopardy situation of high liabilities and also high operating costs.
Several methods can be used to calculate utility debt. The method normally relied upon in Canada, particularly by Crown utilities, in their financial reports, is long-term debt at face value less any long-term debt due within one year. For the purposes of this analysis, a more expansive definition of debt is used, drawn from the debt definition used by NB Power to calculate its debt/equity ratio. Debt here is defined as long-term debt plus short-term debt plus spent fuel management and decommissioning minus cash and short-term investments minus sinking fund investments.
By this measure, NB Power’s liabilities sum to $3.149 billion for 2001 and $3.160 billion for 2000 and $3.667 billion for 1994.
A highly levered utility with no major capital projects underway, like NB Power, would normally be expected to generate a significant amount of cash to pay down debt. Instead, NB Power’s debt is dropping only slightly. Debt declined $11 million in 2001 over 2000. The annual rate of decline was $74 million or 2% over the last seven years. At the average rate of debt decline demonstrated over the last seven years, NB Power’s existing assets would have to continue performing at the present rate of profitability without capital investment for over 50 years to pay off the debts incurred acquiring those assets. Many of NB Power’s main generation assets will reach the end of their economic life in much less than 50 years.1
NB Power’s fuel mix, a key factor influencing the structure of its costs, both debt and operating costs, is similar only to Ontario’s.
The former Ontario Hydro’s total liabilities were calculated by the Ontario government at $38.5 billion as of March 31, 1999, at the point of Ontario Hydro’s dissolution. The method of calculating the total liabilities summed the value of the utility’s debts using a fair market value method, the present value of the nuclear waste using a method similar to that employed by NB Power in its accounts, and an estimated market value for the net losses from long-term power purchase contracts.
1 The status of NB Power’s largest hydro-electric unit, the 672 MW Mactaquac dam on the Saint John River, is relevant to NB Power’s rate of paying off its assets. Mactaquac’s concrete is subject to alkali aggregate reaction, a chemical process causing the concrete to swell and become stressed. NB Power has recently received an expert suggesting that the station life will have to be substantially shortened. The current life expectancy extends until 2038 but the plant may become unsuitable for operations as soon as 2015.
Ontario’s high electricity debt was one of the major factors behind the provincial government’s 1997 decision to restructure Ontario’s electricity economy. New Brunswick’s electricity debt is much greater in relative terms than Ontario’s. New Brunswick’s electricity debt relative to the size of the provincial economy is almost twice that of Ontario – NB Power’s debt equals 16% of the provincial economy whereas the old Ontario Hydro debt (defined more broadly than NB Power’s debt) equals 9% of the provincial economy. Electricity debt per worker in New Brunswick is $9,200 whereas in Ontario it is $6,400.2
One indicator of a utility’s ability to bear debt is its net income. Not only is NB Power is the only major utility in Canada in the last several years to generate negative net income except for Ontario Hydro, NB Power’s has persistently generated negative net income. Excluding transfers from internal accounts, the only year in the last 7 that NB Power experienced positive net income was in fiscal 2000. Over this 7 year period, NB Power has been issuing business plans forecasting dramatic turnarounds in the net income performance. For example, in the 1996 Business Plan NB Power forecast that its net income would improve steadily so that by fiscal 2001, net income would be $75.9 million. The actual for fiscal 2001 was a loss of $12 million. Further documentation of NB Power’s consistent overestimate of future net income is available at NB Power’s reply to Energy Probe’s interrogatory #6.
If NB Power proceeds with its three major capital projects, and assuming no cost overruns, no change in NB Power’s current rate of debt reduction from internal cash flow of $74 million per year (the average rate over the last 5 years), a continuation in the decline of population in New Brunswick at the current rate of 1.2% per 5 years and no change in the employment rate, New Brunswick’s electricity debt per worker will be the highest in Canada by 2007 – over $13,000 per worker.
2 NB’s employed population in 2001 is 342,000, therefore debt per worker is $9,200. Ontario’s employed population in 2001 was 5,997,000, resulting in a per worker debt of $6,400. Ontario’s GDP in 2000 was $430 billion, resulting in an electricity debt of 9% of the GDP. NB’s GDP in 2000 was $19.7 billion.
|Public Electricity Debts|
NB Power’s Running Cost is Uncompetitive
Another key financial parameter for utilities is the variable and semi-variable cost of operations. If a utility had no debt, no depreciation of assets, and paid no taxes, its rates would have to recover only its operating costs and fuel costs.
In its February 1996 study of public electric utilities in Canada, the Dominion Bond Rating Service (DBRS) found that NB Power had the highest variable and semi-variable cost structure of the utilities studied. It found that NB Power’s variable and semi-variable costs of fuel and labor are “so high at 3.23 cents per kWh that they exceed Hydro-Québec’s final sales prices to large industrial customers (about 2.75 cents per kWh).”3 The gap between NB Power’s operating costs and Hydro Quebec’s industrial rate that drew DBRS’s attention was 17%. Since the DBRS study was published, the gap has widened. NB Power’s operating cost – 4.3 cents/kWh – is now 22% higher than Hydro Quebec’s average industrial rate, which is 3.5 cents/kWh.4
NB Power has the highest running cost of any comparable utility in Canada. Utilities that rely relatively more on hydro-electric generation and less on coal and nuclear generation normally enjoy lower operating and fuels costs. Nova Scotia Power with about half the hydro-electric market share of NB Power had operating costs in 2000 of 4.0 cents/kWh.5 Saskpower, which has about the same amount of hydro-electric generation and much greater coal reliance than NB Power, had operating costs in 2000 of 3.4 cent/kWh. For HQ in 2000, the comparable figure is 0.24 cents/kWh6
3 Dominion Bond Rating Service, “The public electric utilities in Canada: An emerging problem for provincial credit ratings,” February 1996.
4 ($309 million for operating cost + purchase power $100 million + fuel $401 million) on 18.8 TWh of sales = 4.3 cents/kWh.
5($157 million for O&M + $273.9 million for fuel and purchased power) on 10.7 TWh of sales = 4.0 cents/kWh.
6($2.135 billion for operations + $2.408 billion for electricity and fuel) on 190 TWh = 0.24 cents/kWh.
NB Power’s High-risk Investment Strategy
Not withstanding its weak financial condition, NB Power is pursuing an aggressive expansion strategy.
NB Power has received approval from the Public Utilities Board for its planned $747-million refurbishment of 1000 MW Coleson Cove generating station. The plan requires converting Coleson Cove from an oil-burning unit into an station burning Orimulsion – a bitumen-water slurry marketed by the Venezuelan state oil company. The plan is part of the utility’s efforts to increase exports and provide back up for Point Lepreau nuclear station.
NB Power is seeking permission from the provincial Public Utilities Board (PUB) and the government to invest an amount it currently estimates at $845 million to extend the life expectancy of the Point Lepreau reactor through retubing and other rehabilitation programs.
Experience with other Candu reactors shows that such refits are commercially risky. From 1983-1989, Ontario Hydro attempted a refit of similar scope on four Pickering reactors. Between 1993 and 1997, Ontario Hydro recognized that the refit had been a failure, wrote off the debts it had accumulated to pay for the refit and the other cost reflected in the net value of the station, and put the four reactors into an extended lay-up condition. A large element of Ontario Hydro’s Pickering refit write-offs was debt owing from Atomic Energy of Canada Limited (AECL), the federal nuclear company. AECL and Ontario Hydro had a risk-sharing partnership in Pickering units 1 and 2.
Contrary to many public statement by Ontario Hydro and other nuclear interest groups, the closure of Pickering A was driven in part by a regulatory safety decision. Ontario Hydro had failed to upgrade the obsolete single fast shutdown system on each of the four reactors by the December 31, 1997 deadline imposed by the Atomic Energy Control Board and therefore was forced to close the reactors.
AECL has a risk sharing partnership with NB Power in the Point Lepreau project. This partnership leaves NB Power with substantial risk. One potential risk is that NB Power is relying on AECL’s continued solvency. AECL’s continuing funding from the federal government and the methods for dealing with its unfunded nuclear waste liabilities are currently matters of public discussion and uncertainty. Even if the guarantee is enforceable, the terms of the guarantees leave NB Power with significant financial exposure. AECL has agreed to guarantee that the Point Lepreau station will operate at 80% capacity factor after retubing, however, NB Power’s cost/benefit analysis for the retubing investment assumes the unit will operate at 89%. Another risk is that under the terms of the “Memorandum of Agreement on Plant Performance Agreement”, after the plant generates as much power as is forecast for approximately 6 years following retubing, if the plant shuts down permanently AECL is not required to compensate NB Power for any of its losses. (NBP Interrogatory reply PUB #8) In addition, NB Power has no contingencies if the retubing outage is extended (NBP Interrogatory reply JDI #11)
The failed Pickering A refit was one of the main causes of Ontario Hydro’s financial collapse in 1997. Failure of the Point Lepreau refit would have a more severe impact on New Brunswick than the impact Pickering A has had on Ontario because of Pickering A’s smaller relative size and Ontario’s lower relative electricity debt.
Institutional Uncertainty about New Brunswick’s Electricity Future
NB Power is pursuing it major capital expansion initiatives in the face of uncertainty over the future institutional arrangements for New Brunswick’s power system.
The government released an Energy Policy in January 2001. The Energy Policy sets out a 10-year phase-in for electricity market reforms with the objective of enhancing competition and opportunities for cross-border trade. According to the Energy Policy, the government intends to introduce amendments to the Electric Power Act to allow for private, non-utility power generation consistent with the Energy Policy. Amendments to the Public Utilities Act will also be introduced to amend the Public Utilities Board’s capabilities to regulate in a more open, competitive marketplace. The government has announced that it will issue its opinions on the future ownership of NB Power sometime during 2002. The Energy Policy anticipates the creation of exit fees to recover stranded cost from consumers seeking competitive alternatives to NB Power.
The investment required to return Point Lepreau to service is much greater than that required to return other nuclear facilities to service. Point Lepreau’s refit is forecast to cost more than $1300/KW, Pickering A (for its second major refit) is forecast to cost $728/KW and Bruce 3 and 4 is forecast to cost $227/KW. These comparisons alone suggest that NB Power is risking creating fresh stranded cost just before a new electricity market begins.
NB Power is currently operating with only an acting CEO, a factor that further reduces the potential for a successful major project.
NB Power Nuclear Accounting Issues
NB Power’s regulatory filings at the hearing into the refit of the Point Lepreau station reveal a pattern of overestimating reactor component lives, under-collection of funds for reactor dismantlement and radioactive waste disposal, and deferral of nuclear cost recognition far into the future. The company’s preferred solution is to defer all the costs decades further into the future.
The testimony reveals an undisclosed liability of $120 million. In 1999, faced with more rapid aging of reactor core components than had been expected at Point Lepreau, NB Power reduced the life expectancy of the unit by six years. Shortening the recovery period for the money sunk in the reactor resulted in a $450-million charge.
Although NB Power’s accounts starting in 1999 acknowledge the cost of the reduced life expectancy, the utility has not made a corresponding increased charge by recognizing the liabilities associated with cleaning up and dismantling, or decommissioning, the station after its use. Instead, the utility continued to report decommissioning liabilities as if the station will continue to operate at a high level of production until the end of the original, longer life expectancy, which extended out to 2014.
NB Power’s annual report notes that the assumptions underlying decommissioning costs are different than those used for the recovery of money sunk in the reactor. However, the impact of this discrepancy was not revealed until NB Power filed its testimony before Public Utilities Board on 2002 February 25. The undisclosed liability of $120 million translates into a 3 per cent rate increase if all other costs and assumptions remain the same.1
The Report of the Environmental Assessment Panel on the Second Nuclear Reactor, Point Lepreau, New Brunswick (1985), recommended that “The annual decommissioning levy be scaled so that contributions are higher during the first years of operation.” 7 NB Power has not followed this principle in the funding of decommissioning and radioactive waste disposal at Point Lepreau to date.
Undisclosed decommissioning costs are not the only nuclear accounting concern. The $450-million writedown in 1999 resulted from NB Power taking the most optimistic interpretation of an external technical review of Point Lepreau’s accelerated decay. The utility now claims that the life expectancy of the station must be cut by another two years, to 2006, consistent with the most pessimistic scenario set out back in 1999. The utility is also suggesting that the end may come as early as 2005, an event that would increase the potential writedown significantly.
If the option of investing in a refit for Point Lepreau is turned down, the financial impact of recovering the money already sunk in the station – based on the most optimistic estimate for the shorter remaining service life, combined with the need to recover the undisclosed decommissioning costs – would result in a rate impact of 13 per cent.8
7 The Report of the Environmental Assessment Panel on the Second Nuclear Reactor, Point Lepreau, New Brunswick (1985), Recommendation 38 (a).
8 For the period 2002-2006, subtracting the amortization and decommissioning expectations for the retubing scenario [$758 million] from the non-retubing scenario [$1183 million] equals $425 million. Assume that approximately $50 million in ‘new’ amortization and decommissioning costs are recovered in this period under the retubing scenario. Therefore, the incremental amortization and decommissioning costs are estimated at $475, equal to an annual impact of $147 – 13 per cent of rates.
Even if NB Power had no other undisclosed and underestimated costs, the utility would be facing a severe financial crunch due to under-recognized nuclear waste disposal and decommissioning costs. The utility estimates its costs for waste disposal and decommissioning at $843 million in 2001dollars. Although Point Lepreau is more than three quarters through its service life and its best production years are behind it, NB Power only recognizes $221 million in provisions for these future costs. Recovering its forecasted exposure to nuclear waste disposal and decommissioning costs may drive rates up substantially although the amount will depend on the treatment of interest cost.
Nuclear waste disposal and decommissioning costs may rise further. NB Power’s estimated decommissioning cost is below the most optimistic estimate used by the nuclear regulator in the United States. NB Power estimates $454 million, whereas the U.S. Nuclear Regulatory Commission’s estimates range from $475 million to $715 million for pressurized water reactors, which are smaller and less radioactive than CANDUs.9
Canada’s nuclear safety regulator has grown increasingly uncomfortable in recent years with the nuclear utilities’ historic waste-funding practices. Canada’s nuclear utilities have not set aside money providing for these so-called “back-end” costs in funded accounts at arm’s length from the utility and its other financial obligations, as could be done through segregated trust accounts. Instead, the money collected for back-end costs has been used by utilities to invest in the general equity of the firm.
NB Power’s severe debt crisis directly threatens the back-end provisions invested in the general equity of the firm because its equity, if measured in market terms, is probably negative. Armed with recently upgraded legal powers, the federal regulator is moving toward tighter, U.S.-style financial standards with full funding of back-end costs. Ontario’s decision to start funding back-end costs for nuclear reactors is one of the factors driving up electricity rates there.
If the Point Lepreau refit is approved and the reactor works as efficiently as the utility forecasts, the buildup of undisclosed, underestimated and under-recognized costs can be stretched over the next 30 years. If, as was the experience at Pickering A, the refit proceeds but fails to achieve its cost and production targets, the financial impact could be severe.
Alternative Greenhouse Control Strategies
Nuclear generation has the advantage of not releasing significant amounts of conventional air pollutants, including greenhouse gases. Valuing this advantage for the purposes of investment planning is inherently subjective. The provincial government has no official position on climate change, but has promised that a discussion paper on climate change will be released in 2002.
NB Power applies shadow pricing of $15/tonne to evaluate the investment alternatives it has considered. It is not clear that this evaluation criteria could be publicly acceptable if broadly implemented. If the $15/tonne were actually applied to NB Power’s emissions in the Year 2000, rates would have increased by 15%, an increase that would make rates for most customer classes in New Brunswick the highest in Canada, except for PEI where the rates are indexed to 110% of New Brunswick’s rates
NB Power has a range of alternative low-carbon and no-debt alternatives that it might pursue as an alternative to the Point Lepreau reinvestment. Purchases from Hydro Quebec or Labrador would both come from low carbon hydro-electric sources. Gas-fired cogeneration replacing a combination of NB Power’s forecasted low carbon nuclear production and high carbon coal-fired production could achieve a carbon-dioxide neutral alternative to the retubing of Point Lepreau. During the recent refit of the Irving Oil Limited Refinery in Saint John, the refinery was pre-engineered to incorporate cogenerated power production. Refinery cogeneration is commonly used around the world. It is often twice as efficient as conventional fossil generation, creating opportunities for lower cost power and reduced environmental emissions. Based on NB Power’s interrogatory responses PNB #3 and CCNB #89, approximately 7.1 TWh of gas-fired cogeneration production would be needed – 5 TWh to replace PL and 2.1 to offset coal emissions – to achieve carbon neutrality relative to the planned future.
Lessons on the Potential Pitfalls of Utility Central Planning from Ontario
In the years leading up to its financial collapse, Ontario Hydro engaged in a massive long term central planning exercise that ultimately resulted in the 25 year Demand/Supply Plan. That plan was published in December 1989, subjected to extensive public hearings, and was ultimately withdrawn in 1993.
The Demand/Supply Plan proposed the construction of 6 to 14 new Darlington-sized CANDU reactors, significant CTU capacity, major programs for DSM and non-utility generation, and many other initiatives. The originally estimated cost of the entire program including interest was approximately $100 billion.
Among the assumptions underpinning the plan that proved faulty were assumptions that electricity demand would never decline, that retubed nuclear reactors would operate reliably, and that electricity prices would steadily decline.
Many major stakeholders endorsed the plan including the Association of Major Power Consumers in Ontario representing industrial users, major unions, and the Ontario government. Other key stakeholders, including the Municipal Electric Association and the Independent Power Producers Society of Ontario, supported major elements of the plan.
Many observers in Ontario complained that the Demand/Supply Plan process failed because no new investments were committed through the process. An alternative view is that the Demand/Supply Plan process ultimately succeeded in avoiding a massive increase in debt for a power system which only a few years after the collapse of the plan became recognized as burdened by economically unsupportable historic debt.
NB Power’s analysis supporting its retubing investments echos the approach used by Ontario Hydro in the Demand/Supply Plan. For example, the same discount rates are applied to relatively low risk investments and relatively high risk investments. In addition, the load forecast uncertainty is assumed to grow less after 10 years (see NB Power’s interrogatory response to CCNB #10.) Technological uncertainties inherent to the investments being proposed were assumed to be fully reflected in the analysis. As in the Demand/Supply Plan, NB Power is taking little or no account of market risks, such as consumers responding to higher prices by cutting their demand or self-generating.