Now we have a new deal to sell NB Power assets to Hydro-Québec. Although similar to the original MOU, it is simpler than the first deal. It still provides 14 TWh of electricity and sells generation assets, but addresses many concerns that New Brunswickers had with the original MOU – the transmission and distribution assets are not sold, there is more certainty regarding year six rates and there are some future off-ramps. But there are still many questions regarding its specific details that need to be addressed.
The media have made exaggerated and sometimes erroneous claims and New Brunswickers continue to question the deal.
Yet, the NB Power Board of Directors has approved the deal. Why is that so?
There is a need for some factual information regarding what the new agreement is, what it isn’t and what some of its costs and benefits may be. I attempt to provide it here.
Essentially the agreement has two major components. It sells (either directly through ownership or indirectly through operational control) NB Power generation assets to Hydro-Québec for $3.2 billion and it sets out the general terms between Hydro-Québec and New Brunswick of a power purchase agreement (PPA) to be used by NB Power Disco to supply electricity customers in the province. More on the PPA later; first, let’s address the generation sale.
“If Hydro-Québec can use these assets to make money, why can’t NB Power?” is a good question that has been raised by New Brunswickers. Its answer lies in the nature of the Hydro-Québec and NB Power systems and the current state of the regional power market.
Hydro-Québec has a hydro-based system that can produce clean high quality energy that is surplus to Quebec needs. It has great operational flexibility, in that it can store the surplus as water in its reservoirs and call on it instantly as needed. A shortfall of the system is that it is capacity limited and has barely sufficient capacity to meet Quebec’s peak load in winter.
The NB Power system, on the other hand, is thermal based, with only a small amount of run-of-the-river hydro that has little, if any, storage capability. It currently has capacity that is surplus to N.B.’s peak load requirements but has very limited capability to produce quality low-emission and low-priced energy.
About 45 per cent of our capacity is oil fired and not competitive with either Hydro-Québec energy or with energy from the adjacent New England market. At times when there is significant rainfall/snow melt and loads are low, the N.B. system can have surplus energy, but it cannot be stored. It must either be dumped or sold in external markets at whatever price is available, and that is usually quite low, often near zero, and on occasion negative (a negative price would occur if there is more electricity being supplied into the market than there is demand from customers to use it).
By combining the resources of NB Power and Hydro-Québec into one system, their utilization becomes more efficient and synergistic value is created that enables the supply of load in both provinces to be done at lower cost. It is this synergy that enables Hydro-Québec to provide a power purchase agreement to N.B. at costs less than NB Power can provide on its own. It also can be done at lower financial risk.
The terms of the power purchase
“Isn’t the power purchase agreement simply a 14 TWh energy purchase at 7.35 cents per kWh?” No, it is not! It is much more, but this is a common misunderstanding of what the PPA is. Frankly, it is understandable how people can get this false impression, because the government has only communicated this bundled price.
Let me try to explain all the component pieces of a final power price agreement. It will include energy, but it is much more than an energy purchase. It is a full-requirements contract, which will obligate Hydro-Québec to reliably supply the entire end-use load of New Brunswick at the customer meter. It will include sufficient capacity to meet a peak winter load of about 3,100 MW and the peaks of each month consistent with NB Power’s load forecast. It will supply capacity and energy to meet transmission and distribution losses that are currently equal to about 6 per cent of the end use load. In addition, it will include all of the necessary ancillary services compatible with industry standards to maintain system frequency, to follow the variability of loads (and intermittent generation such as wind generation), to control voltages and to provide for secure operation.
The price of 7.35 cents per kWh is a bundled price that includes all of these components, and it will almost certainly be unbundled in the definitive PPA contract, which likely is yet to be written. As an example, the 6 per cent losses component can be determined to be 0.416 cents per kWh, which means the price of the remaining services at the generator/interconnection terminals is about 6.93 cents per kWh. Removing appropriate costs for the capacity and ancillary services in a similar way will eventually result in an energy price that is much lower than the stated 7.35 cents per kWh.
“How can electricity be purchased at 7.35 cents per kWh and sold to industry at 5.2 cents per kWh? Isn’t that a subsidy?”
On the surface, this has the appearance of a subsidy and has been interpreted as such by Robert Jones on CBC radio and Lisa Keenan in the Telegraph-Journal, both on Friday last. But as explained in the previous paragraph, the power purchase agreement is much more than an energy purchase. It includes many varied services that need to be unbundled with service-specific prices.
Why is this necessary, you might ask? Well, the fundamental principle of rate making is that customers should pay for the services that they use, based on the cost of those services. Considering that different customer classes use different amounts of each service, it is necessary to unbundle all costs into the various functional services and allocate them to customer classes to determine the cost of serving that class. Until this cost allocation process is completed, it is not possible to determine if there is any cross subsidization between customer classes.
This cost allocation process is not simple as evidenced by past rate cases with the Energy and Utilities Board. In fact, the Board has ordered that a new Cost Allocation and Rate Design (CARD) hearing is required before it will hear another rate increase application by NB Power Disco. Until this CARD hearing is completed with unbundled power purchase agreement costs, there is insufficient information to prejudge that any subsidy exists.
Year Six Rates
“Year six rates are unknown and could increase significantly” was a complaint regarding the original MOU. It stemmed from the fact that the rate freeze was to be undone by subtracting unbundled transmission and distribution rates in year five to determine the supply rate. At issue was the unknown cost of transmission and distribution operations at that time.
Would Hydro-Québec cut them significantly so that it could back into a higher supply rate?
This issue no longer exists with the new agreement. The supply rate has been negotiated up front at 7.35 cents per kWh, and the transmission and distribution costs remain under the control of NB Power. Fair and reasonable rates should be able to be set by the Energy and Utilities Board for year six.
“Is there any value to this Hydro-Québec deal other than a small discount in electricity rates? I would be willing to pay more to retain ownership.” This is a common statement from many people that I have talked to. While the agreement does give up ownership and control of generating stations in New Brunswick, it also provides much more value than the rate discounts. It eliminates most of the financial risks associated with generation of electricity that could cause even higher rates in the future. The most significant sources of risk to NB Power are fuel prices, operations, carbon emissions and debt. Let us consider each in turn.
Fuel Price Risk
Next year, assuming that there is an efficient return of Point Lepreau to service, NB Power will be dependent on fossil fuels for about 45 per cent of its energy needs. Of this, 10 per cent is expected to be from a now stable natural gas source. This leaves about 35 per cent of our needed electricity coming from coal and oil at costs that are a function of world oil prices. The level of risk is that for every $10 per barrel change in world oil price, there will be a corresponding change in fuel cost to NB Power of about $40 million. This is based on an oil price of $70 per barrel.
I leave it to the reader to decide the probability of cost savings for prices below $70. My bet is that prices will rise as the world continues to climb out of our current global recession and the demand for oil increases. Either way, the Hydro-Québec power purchase agreement is at a fixed price, so the risk of cost variations for fuel prices goes away.
If power plants with very low fuel prices, like hydro and nuclear stations, do not operate at their budgeted performance level then they can cause significant cost variations. The fuel replacement value of their under-production or over-production is significantly more than planned.
The hydro system in N.B. is expected to operate at its long-term average energy production, but variations in river flows from year to year can cause swings in the fuel and purchased power budget by as much as plus or minus $50 million per year. Over the long-term this risk averages out, but it can create serious cash-management issues from year to year.
The performance of Point Lepreau is more problematic. While it has, in the past, performed above target for long periods of time, the major concern is extended performance below target.
We are all aware that the replacement power cost during a Point Lepreau outage is between $600,000 to $1 million per day. Currently, because of low natural gas prices in the New England market, it is near the bottom of this range but in future could well increase again. Sporadic outages are a concern, but a much more serious issue would be a significant extension of the current refurbishment outage. If it continued for several additional months or even a year, it could add $200 to $300 million in costs. However, under the Hydro-Québec power purchase agreement, replacement energy is included in the 14 TWh supplied to New Brunswick and any potential replacement costs will be mitigated.
Carbon Emissions Risk
Today there is no price on carbon emissions, yet we all know that climate change is a major global issue and that carbon emissions must be reduced. Of all sectors in society, the electricity industry is being targeted for the largest share of reductions. The G8 leaders have a target of 70 per cent or more reduction by 2050, and the electricity sector is expected to achieve at least 80 per cent reductions. For N.B., which had emissions equal to 6.3 million tonnes (Mte) of CO2 equivalent in the Kyoto base year of 1990, it means that we will have to reduce from our current emissions of 7 Mte to about 1 Mte. This is a tall order and will require almost total elimination of fossil-fueled generation or the purchase of carbon offsets through North American or international markets.
At the $30-per-tonne carbon tax proposed in the last federal election, this would be an additional cost of $180 million per year. There is no firm method yet to price carbon and no absolute requirement to reduce emissions through either a carbon tax or a cap-and-trade system. But one is expected soon and it will increase costs of electricity supply for NB Power. However, under the Hydro-Québec deal. N.B. will receive 14 TWh of clean electricity at known prices with no carbon cost risk. The obligation to meet carbon targets will be borne by Hydro-Québec.
Debt and Interest Rate Risk
Based on the first MOU, we are all aware that the expected debt of NB Power after the Point Lepreau refurbishment is completed will be about $4.75 billion. At this level of debt, a 1 per cent change in interest rates would be about $50 million in increased cost annually. Fortunately, NB Power debt is a mix of long- and short-term debt instruments that shield it from some of this debt risk. However, about $2 billion of this debt has been financed in recent years at very low rates. Similar to how mortgage payments increase dramatically at renewal after a five-year term if interest rates have gone up, the same could happen to NB Power refinancing payments.
Considering that interest rates are at their lowest levels in years, there is no positive outcome here. The risk is definitely slanted toward higher financing costs in the future. With Hydro-Québec reducing the debt by $3.2 billion, the level of risk borne by NB Power and its customers is significantly reduced.
Independent System Operator
The original MOU included the elimination of the New Brunswick System Operator (NBSO) and the transfer of its functions into the transmission company to be owned by Hydro-Québec. As noted by Gordon Weil in his AIMS Commentary, “this transfer raises questions about the ability of the new transmission operator to be truly independent of Hydro-Québec and to operate the transmission system without preference being given to its owner.” In the new agreement, the NBSO is retained as an independent entity that will ensure open, non-discriminatory transmission access is preserved. It also provides greater opportunity for the Maritimes Area to form a regional market and to continue to forge closer integration with New England. This is an improvement in the deal that should benefit the entire region.
As I stated earlier, I offer these comments to assist in understanding the essence of the revised agreement. In my view, it is a financial risk-mitigation strategy for N.B. with the goal of providing electricity customers with lower rates and shielding them from future cost risks. It does require that some specific terms of the power purchase agreement will need to be addressed in the definitive agreement, but overall it is the basis of a deal that provides value for N.B.
William Marshall is President of WKM Energy Consultants Inc. and Past President and CEO of New Brunswick System Operator.