Zapped May Be Good Politics, But It's a Bad Basis For Policy
Overview
“Zapped: A Review of BC Hydro’s Purchase of Power from Independent Power Producers” (the “Report”), is an independent review conducted for BC’s Ministry of Energy, Mines, and Petroleum Resource. The Report reaches a number of conclusions. Many of these determinations, however, rely on incorrect assumptions about both the amount of power that BC Hydro needs, and the real market costs of acquiring that power.
The result: the Report reinforces the view that BC is awash in electricity, and that BC Hydro continues to pay far too much for the energy it has purchased from Independent Power Producers (“IPPs”). The reality is very different.
The Report’s arguments are headline grabbing. The central thesis is that the previous Liberal government inappropriately influenced BC Hydro’s planning parameters – by mandating self-sufficiency, assuming low output levels from BC Hydro’s dams, and restricting BC Hydro’s own resource development – all in an effort to artificially increase the demand for IPP power.
The cost of these mistakes, the Report says, is between $17 and $25 billion. But these figures arise almost entirely from two basic mistakes.
First, the Report fails to critically assess BC Hydro load-resource balance (the relationship between the utility’s supply of energy and the demand for it). The Report assumes that BC Hydro bought power 20 years before it will be needed; in fact the need is imminent.
Second, the Report misunderstands the economic relationship between spot-market prices (which typically don’t provide a project owner with any return of or on invested capital) and the price of long-term electricity supply contracts (which do typically provide for capital returns). A utility planning for its obligation to serve customers cannot rely for its supply on the surplus of other utilities’ portfolios (which is where the spot market gets its electricity). Instead, it should expect to buy power under firm, long-term agreements, and to pay the associated firm, long-term price, for the majority of its portfolio.
The Report does a somewhat better job on policy matters. It does well to recall the history of BC’s energy planning in the past twenty years, and brings to light a number of serious policy shortcomings, such as a pattern of diminished regulatory oversight. At the same time, however, the Report overlooks other serious failings, such as poor procurement practices and the wholesale misallocation of risk between BC Hydro and IPPs – policies that drove up IPP costs unnecessarily, and did more than anything else to cause good supply options to languish un-built.
Ultimately, Zapped is a lost opportunity to analyze seriously an issue that warrants careful review. BC needs energy sooner than it thinks, and it has no institutional structures in place to either plan for that need, or to execute on it. This would always be a problem, but with CleanBC leaning heavily on electrification to meet BC’s greenhouse gas targets, the perspectives raised by Zapped need an immediate, thoughtful, and less partisan, reconsideration.
The Wrong Forecast
The Report’s headline finding is that Government’s policy directives caused BC Hydro to overbuy electricity – an action that Zapped says cost BC Hydro ratepayers $17 billion dollars. The Report reaches this figure by assuming that all IPP-purchased energy will be surplus to need for 20 years, and during that period will be sold into the Mid-Columbia (“Mid-C”) spot-market.
As such, in calculating the cost to ratepayers of Government polices, a projection of when in the future BC Hydro will need electricity, and thus no longer be in a situation of having surplus from past “over-buying”, is a critical part of the equation.
The Report assumes that energy purchase agreements (“EPAs”) with IPPs run for 30 years (evidence that the EPAs are, in fact, long-term supply agreements, not “spot” purchases). From this assumption, the Report states that the cost from “over-buying” over the life of the relevant EPAs is in the range of $25.5B. To reach this figure, the Report simply takes the difference between the long-term IPP prices paid by BC Hydro and the short-term spot prices (where BC Hydro is assumed to sell the power), and multiplies the result by contract volume and term.
Having raised this headline number, the author then concedes that it is wrong to assume that BC Hydro has no need of the power it has bought for 30 years. Instead, the Report leans on BC Hydro’s assertion that its energy surplus will end sometime in the 2030s, due to projected load growth. As a result, the Report modifies its cost conclusions by switching to a 20-year surplus period, resulting in a $17B estimate for the impact of the policy directives.
This highlights the importance to the Report’s conclusions of having a clear understanding of BC Hydro load-resource balance. By assuming the “over-buy” will end by the 2030s rather than a decade later, the ultimate cost figure being claimed is reduced by $8.5B.
Unfortunately, the Report does not appear to have made any serious, independent effort to consider this question further – that is, to consider when BC will actually find itself in need of new generation. BC Hydro’s current view, and the view repeated by the Report, is that new energy resources to meet future load demand will not be needed until 2032. This forecast, apparently arising from BC Hydro’s Fiscal 2017-2019 Revenue Requirements Application, is based on new and planned BC Hydro resources, including Site C, Revelstoke 6, the now-terminated Standing Offer Program, IPP renewals and sharply increased demand side management (“DSM”) measures.
However, this forecast, which has become received wisdom in the Province, requires thoughtful review. In particular, there does not appear to be any substantive basis for counting on the sharply higher level of DSM savings on which the forecast relies. Tellingly, BC Hydro’s latest Service Plan does not repeat the optimistic DSM expectations (in fact cutting the 2020 DSM targets by 50 per cent), and does not appear to fund them (in fact, DSM spending is decreasing). This hardly inspires confidence in BC Hydro’s ability to reach the targets that are responsible for conservation-based delays in new generation additions.
In short, there is simply no history, and no apparent plans, on which to confidently conclude that BC Hydro will achieve its extraordinary DSM targets.
While over-relying on future conservation for its forecast, the Report attributes a significant portion of BC Hydro’s “over-buy” to past reductions in industrial load in the province. While it correctly observes that industrial load, primarily from the forestry sector, was reduced in the wake of the 2008 financial crisis, this focus on decade-old events, which transpired in a drastically different global economic climate, is unhelpful in predicting what comes next.
Moving forward, there is reason to believe that industrial load in BC will increase (perhaps sharply) due to intended electrification arising from CleanBC, and from other policies attached to BC’s GHG reduction targets.
For example, if any of the possible Kitimat LNG, LNG Canada (Phase 2), or Steelhead LNG projects were to develop using electricity for liquefaction (an energy consuming process normally handled by gas turbines), such a plant would consume virtually the entire 5,100 GWh per year output of Site C. Such a decision alone would trigger an immediate demand for new generation in the province. And this is before other electrification targets of CleanBC, including transportation, buildings, and upstream oil and gas activities are taken into account.
These factors considered, it seems that BC Hydro’s and the Report’s view that new energy resources will not be needed until 2032 is based on suspect DSM optimism and a failure to align forecasts with a growing electrification demand from industry. More likely, BC Hydro will need new energy much earlier than 2032, and any “over-bought” electricity will, in fact, be consumed much sooner than the Report anticipates. Given the Report’s $17B cost conclusion is extremely vulnerable to projections about the duration of BC Hydro’s surplus, the stated figures should be viewed with considerable doubt.
The Wrong Market Price
Much as the Report concluded (wrongly) that BC Hydro bought huge volumes of power it wouldn’t need for 20 years, it also concluded (again, mostly based on a misunderstanding of electricity markets) that it paid too much for that “over bought” power. This is not to say that BC Hydro bought IPP power well – it didn’t, mostly because it pushed risks onto IPPs that it was not cost-effective for them to bear. The total cost of IPP purchases could have been materially reduced, at a benefit to both BC Hydro and the IPP industry, by smarter contracting. It is to say, however, that there should be no expectation that BC Hydro (or any other utility) can buy firm, long-term electricity at spot-market prices.
The Report’s misunderstanding of this issue is made plain, for example, on page 68. There, the assertion is made that there is a single price for electricity, and for BC Hydro that single price is represented by the Mid-C index. This false premise serves to undermine the thesis and conclusions of the Report.
There is, in fact, no single price for electricity, but rather a host of prices depending on the terms and conditions of the transaction. Most fundamentally, there is bright-line distinction between prices under firm, long-term EPAs and prices at which spot-markets transact. Because the Report fails to recognize (and, in fact, rejects) this distinction, its findings are inevitably incorrect.
The “single-price” discussed in the report, the “Mid-C Reference Price”, is not reflective of the cost of electricity to utilities for planning purposes. Utilities have firm, long-term commitments to serve their customers and, as with any balanced portfolio, they need to broadly match the characteristics of their “buy” contracts with the requirements of their “sell” contracts.
As such, no utility can plan to buy all of its electricity on the spot market. Spot market purchases may form a part of a utility’s portfolio and, as the Report suggests, provisions like self-sufficiency that deny that opportunity can raise costs unnecessarily. But the suggestion that a utility is erring by not purchasing all of its power at the Mid-C spot price is misguided.
The issue is one of basic economics. At Mid-C, the market clears (most hours) at the short-run marginal cost (“SRMC”) of production (that is, a price which covers the variable cost of the marginal producer and makes some contribution to its fixed costs).
Most of the power that flows into Mid-C is the hourly surplus from plants that are under firm contract to one of the utilities in the region. And most of this power comes from hydro, wind, solar, and coal – technologies that have high fixed costs but relatively low variable costs. Unsurprisingly, then, the Mid-C market tends to clear at relatively low prices.
For utilities’ planning purposes, however, electricity must be viewed at a different price, one reflective of the supplying plant’s long-run marginal cost (“LRMC”). The LRMC, unlike the SRMC, reflects not only variable costs of production, but also the return of, and a risk-reflected return on, invested capital. Only by selling at the LRMC will a project recover its full costs, including servicing its debt and equity capital. Clearly, no project (IPP or otherwise) can be financed on the basis of selling its output into a market that pays only its SRMC.
Just as it would be untenable for a generator to negotiate firm, long-term sales based on the SRMC, it would be untenable for BC Hydro to plan its resources by relying to a great degree on purchasing electricity at spot market terms and rates from Mid-C. Relying on other entities to build resources and generate electricity at the LRMC and provide a constant supply of surplus available at Mid-C for a price based on the plant’s SRMC is not a sustainable strategy.
It is true that in some instances there is ample supply at Mid-C available for cheaper than the full cost of new IPP generation. Indeed, it may be possible to rely on such supply for a portion of BC Hydro’s portfolio, in the absence of the self-sufficiency planning constraint. Powerex takes advantage of these arbitrage opportunities, and the unique attributes of BC Hydro’s hydroelectric storage creates important opportunities for BC to benefit from Mid-C pricing (including selling as much as possible during those hours in the year when Mid-C prices are very high because of very hot or cold weather, or because plant outages have eroded supply to the market). However, as a method of long-term resource planning, reliance on Mid-C supply is not an option, so its prices are not a helpful planning reference.
It is clear that there is not one price of electricity. In fact, the price of electricity used in the Report is unrepresentative of the price considered by utilities when forecasting and planning. Therefore, the claim that BC Hydro has overpaid at every instance that it was paying for firm, long-term electricity through an EPA, at prices higher than the Mid-C spot price, is wrong and based on incorrect economic premises.
The Need to Consider Risk
The conclusion that BC Hydro has been paying too much under its IPP contracts because the firm, long-term purchase of electricity attached to these contracts was at times higher than the Mid-C reference is incorrect for another reason. Specifically, it is necessary to consider how risk premiums affect the price of electricity in EPAs compared to the reported cost of projects that BC Hydro builds itself.
A comparison of how the process of building a generation project would differ for BC Hydro and an IPP illustrates how the Report fails to consider the economic consequences of risk. This is particularly important in the current circumstance, where BC Hydro’s procurement process has saddled IPPs with risk profiles that inflate their contract prices relative to the stated costs for BC Hydro’s own projects, like Site C .
BC Hydro’s procurement process has consistently required IPPs to commit to their sale price and firm deliveries in the early stages of developing a new project, before either capital costs or operational factors can be known with much certainty. Effectively, the price bid at this stage would represent an estimate of necessary electricity rates to make the project economically viable (to recover the LRMC). But because the bid comes early in the process, with few if any mechanisms for upward adjustment, to be financeable most plants have to bid a price reflecting something like a worst-case scenario – highest capital costs, and least favourable operating costs and production volumes. To bid otherwise risks being unable to cover costs, including capital servicing. This risk premium is baked into the price, and is paid by ratepayers whether the worst happens or not.
In contrast, BC Hydro maintains flexibility at this early stage, because its cost-based, regulated rates mean that its risks are borne by their ratepayers as actual costs are incurred. Should costs go over projection, or production fall below expectations, for example, these excess costs or lower value can simply be passed on as an increase in electricity rates. And while normally regulators put some limit on this flow-through of actual costs where the utility’s expenses were found to be imprudent, Governments in BC have largely protected themselves from such discipline, preferring certain dividends over utility moral hazard.
This difference makes IPP contracts seem more expensive, because early on in the process IPPs have to bid a price that monetizes all of their risks, whereas a similarly-timed BC Hydro price estimate has no reason to reflect the potential costs it knows it can simply pass through later.
But it’s not only an apparent cost difference. The IPP price is typically higher because it necessarily includes risks that may never occur – like cost overruns – but for which a risk premium is nevertheless embedded in the IPP bid price. The same non-materializing risk is simply un-costed and unpaid when BC Hydro is the developer.
Critically, this issue is a function of how the procurement has been done. Forcing fixed bidding too early in the process and intentionally pushing all risk onto IPPs, who are generally inefficient at accepting it, is a process problem, not an inherent IPP problem.
Economics would suggest that to reduce associated social cost, risk should be spread over a greater number of projects, and across the most diversified portfolio. With this in mind, BC Hydro and government would benefit from a re-thinking of policy with regard to procuring power from IPPs. BC Hydro could reduce these excess risk premiums – and lower total costs – by moving risk to the party able to bear it most cheaply and by using cost-based pricing set later in the development timeline. Thus far they have simply chosen not to do so.
Spreading risk across BC Hydro ratepayers, even while contracting with IPPs, is better policy. The effect of policy change when negotiating EPAs in this manner could be material.
Other aspects of BC Hydro’s procurement process could also be improved. The Report notes that an issue when dealing with IPPs is having companies abandon existing contracts in order to apply during later calls, when higher prices are expected. In a world where there is no penalty for this type of behaviour, there is incentive for “skunk bidding”, a burden on the process. If policy existed that sanctioned poor bidding practices, the market would serve to create a more efficient process in which accepted prices more accurately reflected market rates.
These policy shortcomings highlight the fact that the problem in BC is not the IPPs themselves. IPPs are not causing BC Hydro to buy the wrong amount of power. They are not causing risks to be misallocated, and over-monetized. In short, they are not creating the financial burden on ratepayers. This conclusion, as it was reached in the Report, is based on flawed premises. What the Report did show, however, was that a major problem is the way BC Hydro contracts with IPPs. This is a problem that can be solved with better policies and practices.
“Zapped” takes a narrow and at times backward looking view of the energy sector. This lens, combined with critical economic errors, produces findings that catch the eye but don’t stand up to tighter scrutiny. The overly simplified conclusion of the Report – that IPPs have cost ratepayers a massive sum – is based on the notions that: (1) BC generally did not need the energy that it acquired from IPPs; and (2) that the EPAs agreed to were substantially over-priced.
This paints an inaccurate picture. A review of the involved economics shows the fallacy of assuming that Mid-C is the “one price” for electricity. At the same time, a review of the supply-demand forecast underpinning the Report should raise concerns that BC will need new power much sooner than the Report anticipates.
Government has goals to both foster economic development and to mitigate GHG emissions. This will take creative solutions, including meaningful plans to electrify industry. Given these goals, BC’s future will call for more energy, not less.
BC must not reject the idea of procuring future resources from independent producers on the basis of bad math, past policy shortfalls, and a lack of foresight. Instead, BC needs thoughtfully developed policy frameworks that enable an informed approach to working with IPPs. In navigating the complexity that is economics and the environment, maximizing the number of good options available to policymakers is key.