When the ‘on’ switch was thrown at the first electric power plant, Thomas Edison was not there celebrating with his team of scientists and engineers. Rather, he was celebrating quite a distance away on Wall Street with the bankers who financed his endeavour. Throughout his prolific career, he understood that a great new design is nothing more than an academic exercise unless the banking community is willing to provide the requisite funds for construction.
Today’s nuclear engineers may want to consider that moment in history. The designs for the next generation of nuclear power imply greater safety, and modular construction may improve costs. They may also help countries meet their greenhouse gas targets. Nonetheless, recent research has demonstrated that within deregulated electricity markets, such as those that comprise two-thirds of the US electric market, there should be little expectation of obtaining the requisite financing to construct these new designs.
Market evolution
Much has changed about electricity markets over the last few decades. Previously, all utilities in the US that owned nuclear power plants operated within a regulated cost-of-service framework. These long-standing cost-of-service regulations extend back to several US Supreme Court decisions including Smyth v. Ames and Hope Natural Gas v. Federal Power Commission which led to the ‘used and useful’ doctrine for regulated monopoly utilities. Moreover, all retail customers within the geographic boundaries of a utility’s service territory were legally captive – they could not switch electric providers no matter how high the regulators set the electric rates following placement of a new nuclear plant into the rate base, or how volatile due to an oil embargo. From the viewpoint of lenders and investors, these captive customers provided the ultimate credit support for a utility’s construction plans. Under a regulated monopoly utility framework, the revenue and cost risks of owning a nuclear plant were reduced to a point sufficient to satisfy the financiers.
This regulatory framework supported the financing of more than 90 GW of nuclear capacity in the US. Globally, it supported the financing of over 400 nuclear power plants in 32 countries, and every one of these nuclear plants was financed under some form of government regulation. Referred to as the “sovereign form” of financing by the International Atomic Energy Agency, either the government agreed to assume some or all of the revenue and cost risks, or the government passed the risks on to captive retail customers. Without some form of sovereign assistance, no nuclear power plant in any country has successfully secured financing anywhere in the world.
Within the US, electricity deregulation began with the passage of the Public Utility Regulatory Policies Act of 1978, followed by the Energy Policy Act of 1992, and then by various Federal Energy Regulatory Commission (FERC) rulings. These rulings included Orders 888, 889, 1000, and 2000 to further promote competitive economic efficiencies by providing open access to electric transmission lines and establishing the independent system operators (ISO), thus creating an ‘arms-length’ separation between the operation of the transmission grid and its owners.
Arising from this string of legal and regulatory changes was a restructured electricity market serving approximately two-thirds of the US market. Here, electric utilities were required to divest their regulated electric generating assets, and electric plants are now developed, owned, and operated by non-utility independent power producers (IPPs). No longer are there regulated monopolies for the generation of electricity. There are competitive wholesale and retail electricity markets, and retail customers are free to choose their electric suppliers the same as they choose cell-phone carriers. These IPPs sell their electricity into the wholesale electric grid as a commodity using prices provided by each IPP to the ISO on a daily basis. Cost-of-service regulations are not available to these IPPs. They survive, or not, on their ability to make a return on investment in a competitive market – the same as other competitive businesses such as automotive manufacturing, oil and gas, pharmaceuticals, and food products.
The goal of engineering economists several decades ago to deregulate and restructure the electricity generation market, and bring economic efficiencies through competition, has largely succeeded. Numerous studies have shown that deregulation led to increases in operating performance and plant efficiency, as well as lower electricity prices for customers. However, deregulation also shifted some risks away from electric ratepayers and toward power plant investors. There are multiple types of risk which affect the construction and operation of a power plant, and it is the shifting of revenue risk and how this risk affects different types of power plants differently that is a key to private sector investment in power generation.
Changes in dispatch risk
It is well established that the economics of a high fixed cost/low variable cost technology such as nuclear power improve at higher capacity factors, typically represented as the baseload segment of the market. Capacity factors of 90%+ are considered the critical range of operation if nuclear power is to be cost-competitive vis-à-vis competing technologies, and this characteristic has important financing implications. In other words, it is important to maintain a high output quantity (Q) to keep average fixed costs (AFC) down because nuclear plant fixed costs are high relative to its variable costs. Thus, by operating as a baseload unit, the high fixed costs of a nuclear plant can be allocated over a greater quantity of kWh to minimise AFC, which in turn, minimises the plant’s average total electric costs.
Thus, it is economics, not physics, that restricts nuclear plants from being dispatchable (changing Q during the course of a day to meet changes in electric demand) as this would lower Q and, in turn, increase AFC. The nuclear plant would have insufficient cash flow to meet its debt and equity obligations.
This economic principle that nuclear plants should not be dispatchable also applies to any of the proposed advanced nuclear plant designs. These new designs do not alter the high fixed cost/low variable cost relationship that is inherent to nuclear power, and it is this relationship that dictates whether a power plant economically operates as a baseload, intermediate, or peaking unit. The new designs do not alter the economic issue at the centre of our analysis with its important financing implication that nuclear plants require baseload operation.
The conundrum, whether analysing existing nuclear plant technology or a proposed advanced modular design, is that the daily quoted price (P) of the electricity supplied by the owner of the plant to the ISO must remain low enough to ensure that the plant will be dispatched by the ISO in order to sell a high quantity (Q) of the plant’s output, and thus be a baseload unit, yet the total revenue (TR = P x Q) must be large enough to cover all costs, including the plant’s high capital costs. This is a tight operating window, and the nuclear plant must be able to satisfy this constraint over the plant’s life, despite changes in competing technologies, regulations, and customer demand in order to attract financing. The debt and equity financiers of the nuclear plant seek to have this operating risk minimised because the tight operating window leaves little cushion to absorb the effects of other long-term revenue risks.
Prior to deregulation, nuclear plant owners were able to eliminate this dispatch risk by designating each nuclear plant as “must run”. Today, under deregulation, this ability no longer exists because the dispatch sequence is determined by the ISO and not by the owner of the power plant.
Changes in price and output quantity risks
Lenders and equity investors have concerns about long-term price certainty for all types of power plants, not just nuclear. The concern is that the power plant will remain capable over the long term of selling its output at a price that is high enough to cover its costs. Adding to this concern is the possible emergence of any new, competing technology that can sell electricity at a lower price. The ISO may sequence the new technology to run each day ahead of the older technology. When this occurs, the new technology will push the older plant ‘up the dispatch curve’ which will result in a shortfall of total revenue for the older technology and affect its ability to make payments to lenders and investors.
Prior to deregulation, power plant owners were able to eliminate this long-term price risk based on the previously noted Supreme Court decisions which established the ‘used and useful’ doctrine for regulated monopoly utilities. Under this doctrine, once a power plant is deemed to be used and useful by the appropriate regulatory body, then the prudently incurred costs, including the plant’s fixed capital and the variable fuel costs, plus a reasonable rate of return, continue to be included in the electric rates charged to customers. Today, under deregulation, this ability no longer exists.
Another financing concern is price volatility. Each power plant within an ISO region competes with each other based on price. Daily prices quotes are submitted to the ISO, much like a limit order for the sale of stock on a stock exchange. The submitted electric prices are combined with the estimated daily market demand by the ISO to create the daily dispatch curve. The actual interaction of supply and demand, as it changes throughout the day, determines the actual wholesale prices paid and the quantity of electricity sold that day by each power plant. The supply and demand curves for electricity are inelastic, and because of the continually changing interaction of supply and demand throughout the day, electricity prices determined by the market can be more volatile than regulated prices. Downward price swings can affect the ability to meet debt and equity obligations.
Prior to deregulation, power plant owners were able to eliminate this price volatility through the above-noted ‘used and useful’ doctrine by which this volatility, as seen by the investor, was smoothed out by the periodic rate-making process. Today, under deregulation, this process no longer exists.
Lenders and equity investors are also concerned about long-term output quantity certainty for all types of power plants. One concern is that a power plant is unable to generate power at full output for technical reasons, such as the historical need for many nuclear plants to plug leaking steam generator tubes, which reduces output. Prior to deregulation, power plant owners were able to eliminate this long-term output quantity risk based again on the ‘used and useful’ doctrine so long as the owner took reasonable efforts to repair the problem. As a general rule, the prudently incurred repair costs would also get to be included in the rates charged to customers. Today, under deregulation, this ability no longer exists.
Another long-term financing concern relating to output quantity is the ability of a power plant to maintain a market for its output. Prior to deregulation, all of a utility’s retail customers were captive – they could not switch electric providers no matter how high the regulators set the electric rates or how volatile. From the viewpoint of the lenders and investors, these captive customers provided the ultimate credit support for the utility’s construction plans. Today, under deregulation, this ability no longer exists, and electricity customers are now able to choose based on price among competing electricity suppliers.
It is evident from the above that the underlying basis that supported the financing of all power plants has changed due to the transition from cost-of-service regulation to deregulation. To summarise, we have the following changes to revenue risk:
- An exposure to baseload output quantity uncertainty due to ISO dispatch rules which include the elimination of “must run” designation,
- An exposure to price competition from existing and future power plants located within the same ISO region,
- An exposure to price volatility amplified by the inelasticities of the electricity supply and demand
curves, - An exposure to output quantity uncertainty as retail customers, who are no longer captive, can switch electric suppliers thereby leaving a power producer with excess ‘inventory’, and,
- An exposure to future changes in law and regulation regarding the sale of electricity
The above changes in risk exposure, individually and/or in combination, have increased price risk and output quantity risk as seen by lenders and investors. Consequently, they have negatively impacted debt and equity parameters.
Impact on debt
Globally, non-regulated electric power projects all use project-financing to obtain the requisite funds for construction. Project financing can be defined as a separable capital investment owned by a special purpose company in which the lenders look to the cash flow of the project to service their loans, as well as to provide the return on, and return of, the participants’ equity contributions. The advantages of project financing are the availability of non-traditional loan sources, off-balance sheet treatment, and the ability to prevent recourse to an affiliate (including the parent company) in the event of a project’s default. The disadvantage of project financing is that the lenders only look to the cash flow of the project to service the loan which limits the pool of projects that can satisfy the loan covenants. Non-regulated electric power projects cannot use balance-sheet financing, and it was balance-sheet financing that was used to obtain the financing to build every nuclear plant everywhere around the world.
A primary task for lenders is to determine whether the project will generate enough cash flow to cover the debt and pay dividends to the equity participants, and this determination considers all project risks and uncertainties, including the changes in revenue (price and output quantity) risks discussed previously. Based on the risks of a power plant project, the lender(s) will establish a minimum debt coverage ratio (DCR) and then calculate whether the project’s cash flow meets this minimum. The DCR is the primary tool used by lenders to account for such risk. Increasing the interest rate offered to a project is also a method used to account for risk, however, a change in the interest rate is captured in the calculation of the DCR and, thus, ultimately, the DCR remains the primary tool.
If the project’s pro forma financial statements indicate that there may be instances where the minimum DCR will not be satisfied, the lender will either impose a new, lower debt:equity (D:E) ratio that will satisfy the minimum DCR requirement, or choose not to participate as a lender to the project. Therefore, an increase in any risk, including revenue risk, affects the willingness to lend.
Moreover, a lender’s insistence on imposing a higher minimum DCR, while holding the project’s capital costs, revenue, and all other non-debt expenses constant will, by definition, lower the D:E ratio and thus require an increase in the quantity of equity. This creates a problem for the equity investors: it reduces their return on equity (ROE). The above financial concepts (DCR and D:E ratio) and their relationship to an increase in risk have been tested extensively and supported by financial research for over four decades.
Impact on equity
The impact of risk on the valuation of equity has also been well-studied for many decades. The financial marketplace demands that assets with identical risk have the same rate of return on equity, and assets with higher risks require higher returns. In addition, the financial marketplace will adjust equity valuations due to an adjustment of the imputed cost of equity upon the arrival of new risk information. This includes information regarding the deregulation of electric markets and, as such, changes in revenue risk arising from deregulation will get reflected in the minimum required ROEs of electric projects. This creates a double whammy for equity investors: increases in risk increase the minimum DCR, which results in a lower ROE. At the same time these increases in risk lead to a higher minimum required ROE. Both of these factors, individually and/or jointly, work to reduce the availability of equity.
Moreover, baseload power projects such as nuclear should be affected by the exposure to output quantity risk greater than a technology that is designed for peaking or intermediate dispatch. While research has shown that every electric generating project faces increased revenue risk from deregulation, baseload projects such as nuclear with their high fixed cost/low variable cost structure that are vitally dependent on maintaining a high Q to ensure a low ATC, face an even greater revenue risk and thus further affect the availability of debt and equity financing.
Impact on the cost of capital and the availability of funds
As already discussed, revenue risk affects the D:E ratio and the minimum required ROE, and both of these are inputs to the calculation of a project’s weighted average cost of capital (WACC). Thus, as risk increases, so does the WACC. For those investments that make use of project-financing, such as every power plant in a deregulated market, research has conclusively demonstrated that investors will provide funding sequentially in accordance with the ratio of each project’s internal rate of return (IRR) to its WACC. New power plants with high IRR:WACC ratios will get funded first and so forth down the line until either: a) the electric market demand is satisfied and there is no longer a need for the projects with lower IRR:WACC ratios, or b) investors have expended all of the funds in their energy portfolios. Those technologies with high IRR:WACC ratios attract funding. Those technologies with lower IRR:WACC ratios are unlikely to attract funding. Ratios less than unity have no chance of obtaining investment. The IRR:WACC ratio forms a straightforward metric for understanding which power plant technologies will obtain financing within deregulated electricity markets.
High fixed cost/low variable cost projects, such as nuclear, will have a higher WACC relative to other technologies due to the change in dispatch risk caused by deregulation. Everything else being equal, this higher WACC in the denominator of the IRR:WACC ratio will lessen the availability of investment funds for nuclear.
In deregulated markets, all power plants selling into the grid within an ISO receive the same P at the same time, and thus the primary drivers affecting IRR are the capital cost of the power plant and its fuel cost. A quick comparison based on US Energy Information Agency data between several high fixed cost/low variable cost technologies shows the capital costs of wind and solar to be much less than the estimates for the new advanced modular designs, and this lower capital cost is what drives a higher IRR for wind and solar. The higher IRR in the numerator of the IRR:WACC ratio will increase the availability of investments funds for these projects and lessen the availability of investment funds for nuclear. To date, funds for nuclear within deregulated markets have been unavailable because there have been more than enough projects with higher IRR:WACC ratios to satisfy market demand. So long as there are projects seeking investment having higher IRR:WACC ratios, nuclear power will be crowded-out of the financial marketplace within deregulated markets.
Regulated vs. deregulated markets
The key distinction regarding the availability of financing for nuclear plants is regulated markets versus deregulated markets. For example, the recently completed Vogtle nuclear units were constructed within the one-third of
the US market that remained regulated. The units are owned by a regulated utility and thus were able to use balance-sheet financing. The units were able to be placed into the utility’s rate base upon completion as ‘used and useful’, were able to be designated by the utility as ‘must run’, and the utility’s captive customers provided the credit support for financing.
Similarly, the Darlington small modular reactor (SMR) in Ontario, Canada is also being built on a regulated basis. The plant is fully owned by the government and the government has assumed revenue risk including operation of the plant as a “must run” unit. While the Ontario Province has undergone some deregulation with respect to non-nuclear generation, it retains “carve-outs” for its nuclear programme and, as such, the Ontario market is not deregulated with respect to nuclear power.
The Hinkley Point-C is also moving forward, but not on a deregulated basis. For starters, it has a 35-year price guarantee (Contract for Difference) with a fixed price that was set by and guaranteed by the UK government. The Contract for Difference eliminates the exposure to price competition from future power plants and it eliminates the exposure to price volatility. It also takes care of the ‘must run’ problem as it ensures baseload operation for the full term of the contract. Like the Ontario province, the UK has undergone some deregulation with respect to non-nuclear generation, but it treats the nuclear market separately and, as such, the UK market is not deregulated with respect to nuclear power.
Vogtle, Darlington, and Hinkley Point are each an example of the “sovereign form” of financing, and therefore not subject to the increased revenue risks that arise from deregulation. Without some form of assistance where the government agrees to assume some or all of the revenue risk, or the government passes the risks on to captive retail customers, no nuclear power plant in any country has successfully secured financing anywhere in the world.
There’s a chance, albeit small, this may change. Recently, a SMR developer announced tentative plans to address deregulation’s greater revenue risks through a long-term offtake contract with a large retail electricity purchaser. On the surface, the purchaser’s electricity requirements match well with the nuclear units’ baseload output requirements and the long-term contracts could remove price volatility risk. From a financing standpoint, however, this arrangement is problematic for lenders. It is essentially asking to replace the long-term Contract for Difference, backed by the full faith and credit of the UK government, with a similar long-term contract backed by the credit of the customer. Clearly, there is a difference in credit risk – the question is how much?
Long-term contract prices can, and often do, become “out of market” over time, and this is why it is difficult to purchase an electric price hedge contract from a credit-worthy counterparty beyond a six-month term, let along the duration of a typical twenty-year mortgage. Furthermore, contractual take-and-pay obligations to ensure baseload operation may not remain consistent with the purchaser’s ability to use and/or re-market the electricity over time, and this creates new revenue risks.
According to the annual report of the purchasing company, the equipment used by the purchaser in its business has a life of six years, far less than the term of the electricity offtake contract. Thus the company will need to continually purchase replacement equipment with the latest technology on an ongoing basis, as a minimum, to maintain market share (and thus maintain electric demand) throughout the life of the contract, which also assumes the company wants to and can remain in that business for the full term of the contract and/or that the business model for their product continues to exist as we presently know it.
Using previous lender requirements involving natural gas combined cycle projects as precedent, the D:E ratios mandated by the banks increased significantly for those projects without regulatory-approved long-term offtake contracts as would be the case here, thus resulting in a significant reduction in the investors’ ROE and their ability to attract capital. Using previous lender requirements involving oil and gas purchase agreements as precedent, the purchaser will need to demonstrate and maintain sufficient hard assets that could be liquidated if needed as credit support equal to the projected value of the electricity to be sold over the term of the agreement. Investment bankers, still wary over the Enron debacle where too few hard assets provided credit support for the company’s long-term contracts, will take a close look at the difference between the purchaser’s hard assets and its market capitalization, which is relevant here based on the annual report of this purchaser, and a hard look at the purchaser’s hard assets versus the sum of all its long-term contract obligations. Few companies are willing to wear these long-term handcuffs, let alone are capable, especially when other options to purchase electricity exist. To summarize, there is additional risk to be addressed relative to other power plant investment opportunities including regulated nuclear opportunities, and as such, there should be little expectation of obtaining the requisite financing to construct many new nuclear units based on the credit support of a long-term offtake contract with a single customer. Given the choice to finance a new nuclear plant within a regulated framework versus one within a deregulated framework, the lenders’ fiduciary obligations will likely cause its limited supply of funds to flow in the direction of the regulated opportunity due to the difference in credit risk.
Advanced reactor strategy shift required
At the end of the day, the issue facing the financial community is not whether a technology provides firm vs. interruptible power, or where it fits into the dispatch queue. For project-financed projects within deregulated markets, the issue boils down to the IRR:WACC ratio. Debt and equity investors will continue to prudently pour money into wind and solar projects (and any other forthcoming technology) that have higher IRR:WACC ratios. Unless nuclear power can increase its IRR:WACC ratio on par with other technologies, either by lowering revenue risk to lower its WACC or by lowering its capital costs to increase its IRR, nuclear power will not succeed in attracting private investment within competitive deregulated markets.
Deregulation is here to stay in those markets that have been deregulated. Given that there are multiple technologies, and more to come, to combat greenhouse gases, there isn’t the political appetite to rescind the successes of deregulation. Today’s designers of advanced modular reactors may want to adjust their marketing plans to exclude deregulated markets and focus on regulated markets where there isn’t the competition for funds against other technologies having higher IRR:WACC ratios.
