No one is likely to do well in business by focusing exclusively on long-term issues. But every so often the cumulative effect of the change that’s constantly occurring in the world around you has to be acknowledged, and a serious reconsideration of the long term plan becomes essential. When the National Energy Board handed down its historic decision in the TCPL mainline tolls case at the end of March, it was apparent that the Board had been wrestling with difficult questions about how to balance the effects of significant change between investors and shippers. Its decision was important and likely enduring, but it does leave further work to do, and reminds observers that similar questions remain to be addressed in related sectors.
The specific issue at stake in this key aspect of the NEB’s decision was how to recover the full historic costs of building and maintaining a pipeline that was seeing major reductions in flow as the gas supply landscape shifted dramatically in North America. To resolve this question, the Board had to deal with the challenging issue of who is responsible for what costs when a market takes on a shape much different from what was anticipated when the builders first went to the regulator seeking approval to recover their costs. The Board had to keep in mind the importance of maintaining a competitive environment for the development of new pipeline capacity, while also facilitating competition between suppliers of the commodity.
The Board’s decision was that the owner of the pipeline, TCPL, while it can expect to recover a good deal of its prudently-incurred costs for building and maintaining the pipeline, is not protected against “fundamental market risk” including the danger that customers will migrate in large numbers to other pipelines or other sources of supply. This may have come as a shock to many at TCPL considering that the history of the pipeline for 50 years or more has been full recovery for all reasonable costs it incurred as its market grew and changed over time.
When markets change and regulatory arrangements established within them are stretched beyond recognition by the accumulation of changes from outside, sooner or later the NEB or someone has to clarify what happens when new and unexpected forces enter the picture. In the case of TCPL’s main west-to-east line, there was a proliferation of new pipelines and new sources of gas all over North America, making the big pipe from west to east less attractive than other alternatives. The Board had to clarify what kind of protection it was giving to the owners of the pipeline, knowing that at the same time it would be sending a signal to future investors in future pipelines as to the risk of under-recovery they might face in the event of major change in market fundamentals.
Although the following may be a bit arcane for those unfamiliar with regulatory law, many believe that a concept known as a “regulatory compact” should be at work here. Although this is an over-simplification, in principle the “compact” is an unwritten deal between the regulator and the regulated company that says the following:
• The regulated company agrees to abide by terms and conditions set by the regulator while building and maintaining equipment for use by its customers (reducing its potential for upside profit).
• Although this is a long way from being resolved, at least in the view of some regulated entities, the regulator agrees to reduce market uncertainty in certain ways, for example by setting rates for the company’s customers at a level that will reduce some of the uncertainties associated with recovery of reasonable costs (reducing the potential downside risk).
With this kind of a deal, regulated businesses feature both lower risk for the investors, and lower returns, compared to unregulated businesses. These two characteristics are beneficial for everyone in the sense that they make the development and financing of critical infrastructure more definite and predictable. In effect, the regulatory compact reduces the cost of capital for major projects, because it reduces the business risk associated with major investments.
At the same time, consumers may have their own implied compact with the regulator. Consumers benefit indirectly from a regulated utility’s lower cost of capital, and more directly from established standards of service, the increased certainty of major infrastructure development, protection against rate shock, and protection against rates that approach monopolistic rents. However, in return, consumers are expected to pay the regulated rates, which may not always be exactly in line with the latest offerings that might be available from a fully competitive operator.
It should be noted that the NEB specifically stated that it believed there was no defined regulatory compact in this case. Nonetheless key concepts related to the regulatory compact continue to influence thinking in many quarters.
In its decision, the NEB appears to be saying that the regulatory expectations, compact or not, at least with respect to TCPL’s mainline, are being clarified in certain long-term respects. The owners of the pipeline and their investors should not assume that the regulator will guarantee full recovery of all their costs if there are fundamental shifts in the underlying structure of the market. As always, if there are minor changes that cause a few customers to stop using the pipeline, within its established rules, the regulator will expect the remaining customers to shoulder a larger share of the burden to make up for the declining volume. But this principle cannot be extended ad infinitum. If the pipeline becomes uncompetitive or obsolete in some respect, its owners must expect to endure business consequences comparable to those experienced by the owners of any outmoded asset. (In other words, the owners of a regulated asset are still exposed to change in market fundamentals). Like other commercial businesses, the owners of the pipeline must do as much as they can to remain competitive and ensure their assets are as fully utilized as possible even if market conditions change radically, and cannot rest assured that all costs will be fully recovered in all circumstances.
Of course parallels will inevitably be drawn between underutilized capacity in regulated pipelines, and the potential for stranded assets in the electricity sector. When Ontario Hydro was restructured in the 1990’s, massive write-downs were taken to recognize that the debt incurred for certain assets couldn’t be properly serviced by continuing to collect revenue from the kind of electricity rates that were normal at the time. Some of the costs of assets that were belatedly recognized as uncompetitive were charged back to the utility itself through asset revaluation, reducing its capital base, and some were charged to consumers through special unavoidable levies. More than a decade later, Ontario consumers are still paying a debt retirement charge of nearly $7 per MWh (seven-tenths of a cent per kilowatt-hour).
In the 1990s some Ontario Hydro generation appeared out of step with new technology in the market, in part because of the entry of new, relatively low cost gas-fired power plants. In this decade, according to some observers at least, there is a distinct possibility that new technology in gas extraction and photovoltaics (PV) will once again give established suppliers a run for their money. A report from the Edison Electric Institute this January said disruptive technologies like these could cause “irreparable damages to revenues and growth prospects” of utilities. Major US utilities like NRG Energy Inc. and Duke Energy Corp. are recognizing the potential and making strategic moves into PV and distributed generation. The wolves may not be at the door right now, but if history has taught us anything, it’s unwise to assume that technology change and competitively-minded challengers will wait politely until current investments are fully amortized.
Is it wise to allow major utilities to continue to make investments that the public will be largely on the hook for, knowing that those investments may not turn out to be hugely competitive in hindsight? Of course it is, because those investments support necessary infrastructure. However that doesn’t mean the investment processes, especially those in regulated settings, will continue as though nothing potentially risky is happening. There are real risks associated with technology change and market change. Expect regulators to look for new ways of testing investment proposals, and ensuring that long-term risk is appropriately shared between investors and consumers.
However, it can be inappropriate to apply the regulatory model from gas onto electricity without adjustment. Electric distributors in particular are generally viewed as having a particularly wide-ranging “obligation to serve” – which means they have to connect and provide good quality power service to pretty well anyone in their service territory. In return for meeting this kind of obligation to serve, these utilities generally expect a higher degree of protection from changing circumstances in the market.
Regulators always have a difficult challenge balancing the needs of the investors with the reasonable expectations of consumers in such a way as to ensure continued economic operation of the utilities and the ability to attract low-cost capital. Into this context they must insert consideration of the potential for the entry of disruptive technology. A common example has been making sure that distributors in particular are protected against lost revenue when customers start saving energy in large amounts, or switching from electricity to other fuels. For example, the Ontario Energy Board has instituted a Lost Revenue Adjustment Mechanism (LRAM) to ensure that distributors continue to collect the revenue required to build and maintain their systems, even as they encourage customers to use less energy. The OEB is extending this concept even further with a more broad-ranging “revenue decoupling” initiative now underway. Presumably the outcome of this proceeding will allow distributors to be protected from revenue loss across a wider range of volume reduction situations in the future.
With its revenue decoupling initiative, the OEB has demonstrated that it is on the same page as the NEB. It can see the risk of declining revenue related to technology change and/or market change, and the need to help manage the risk with substantive initiatives from the regulator and the regulated companies. Neither regulator is suggesting that customers should be discouraged from adopting new technology or business arrangements that might reduce their volumes. On the contrary, there seems to be wide agreement that customers should be free, possibly even encouraged, to find ways to reduce energy consumption without suffering penalties or other ill consequences, aside from the direct risks of their investments in load reduction technology. In a statement of principles released recently by an APPrO working group on load displacement generation, the group stressed how important it is that customers be encouraged to investigate and deploy new technology that can help them reduce consumption, manage load, integrate power operations with smart grid functions, and generally to innovate with new power generation technology options, without incurring penalties because they are reducing their use of the grid. The group said that “Regulatory arrangements should ensure that (electricity) distributors are in a position where they are able to facilitate and/or embrace new technology, and not be in any way threatened financially because of customer initiatives, even if the initiatives are likely to result in long term load reduction.”
Unfortunately there is a major impediment to this kind of innovation, embedded right in the basic regulation of electric distributors in Ontario. Although the costs of running an electricity distributor are mainly fixed costs that do not vary when customer demands go up and down, distributors’ current revenue streams in Ontario are heavily dependent on rate structures tied to the variable demands of consumers. This means that distributors are heavily impacted when consumers save energy, switch fuels, or install generation. This unfortunate situation has led some distributors to see innovation as a serious threat to their livelihood. Fortunately, others recognize that the problem is not that their customers are trying new things, but that they are saddled with a rate structure mismatched to their cost structure.
The rate structure used by phone companies is a reasonably good example. Local phone service companies in Canada normally charge customers a fixed basic monthly amount set by a regulator, regardless of whether the customer uses the phone a lot or a little. The phone company’s costs don’t vary much with usage and neither does the basic rate. The company’s basic costs are covered and they aren’t threatened if customer usage declines. There is a separate company that charges for long distance service, and customers of course pay for that service depending on how much they use (a “volumetric charge” in utility parlance). A primary benefit of this system is that the phone company isn’t at risk when customers find new and better ways to get long distance service. Although obligatory monthly fees are unlikely to make sense in the TCPL case (because connection isn’t obligatory there) the telephone approach could be applied to electricity, perhaps with even greater impact. Those who find ways to reduce their electricity use would pay only the monthly connection charge, and minimal volumetric charges. More to the point, the distributor wouldn’t feel threatened by innovation and could even help its customers to find new ways to be smarter and more innovative with power. When the customer and the distributor are both uninhibited about exploring options for smarter new technology, the possibilities are almost endless.
Both the NEB and the OEB have recognized that part of the regulator’s role is to encourage healthy competition and efficient market behavior even if that sometimes means declining volume for a regulated utility. The regulated utility is of course obliged to manage all of its costs and risks, and face regulatory challenges the resolution of which are of concern to every market participant. In fact, whether they realize it or not, nearly every consumer has an ongoing investment in successful resolution of utility regulation issues, if only to adapt properly as the market evolves. Although much work remains to be done to ensure that long-distance gas tolls are as competitive as they can possibly be, it is comforting to know that our regulators have recognized that while investors need assurance of some kinds of predictability, that should not impinge on the ability of customers to find new and sometimes unexpected ways to use technology and manage their energy options.
It’s starting to look like long-term vision isn’t an optional extra – it’s another essential service.
— Jake Brooks