Administrative add-ons, in concept, can cover a wide range of possible administrative interventions in the market. The Texas model has been characterized as having fewer such add-ons than any other state regulatory model, comparable in this regard only to Alberta and Australia. For example, in Texas there is no administratively determined reliability standard, such as the “one day in 10 years” outage standard that applies in some areas. So, in Texas there is no reserve requirement applicable to load-serving entities and no administratively monitored or regulated forward capacity market to ensure resource adequacy. In these circumstances, resource adequacy is mostly a matter of customers and suppliers arranging their commercial relationships according to the incentives of the market, there being few administrative back-stops to ensure continuity of supply. The result is a short-term focus on commercial opportunities, needs, and risks. Residential customers are not interested in long-term contractual relationships with retail electric providers, so their promises of customer loyalty extend no longer than a few months in many cases and a few years at most. Commercial and industrial customers are slightly more constant in their commitments, but are nonetheless reluctant to go beyond contract terms of three to five years. Having no assurance of customers beyond a short period of time, retailers are unwilling to contract for long-term generation supplies. Investors in generation, however, are forced by the capital intensive nature of their product—the generation of electricity from power plants that are built to operate for decades—to make a long-term commitment of capital.

Accordingly, investors need some reasonable expectation of a reasonable return of and return on their investment over the long pull. Since it is not possible for investors to amortize the long-term needs of capital according to the short-term needs of customers, there are risks and instabilities incident to an energy-only market design that, without administrative add-ons, make electricity prices more volatile, scarcity pricing more extreme, and supply discontinuities more likely than other models. Customers, especially those used to the certainty and stability of the traditional regulatory model, could find such risks and instability surprising and even disconcerting.

From the beginning of restructuring through at least 2008, the Texas energy-only model worked beautifully. In Texas, the marginal fuel for generation supply is and has been for a very long time natural gas. So the price and availability of natural gas generation in ERCOT establishes market prices and margins for investors. When the market opened up for competition, the inefficient legacy generation in Texas offered investors in Texas clear head room for profitable investment. On top of the relatively inefficient supply stack, natural gas prices began to rise and thus leveraged the efficiency advantages of more modern natural gas generation. In response, even more gas-fired generation was developed and even some solid fuel generation as well. All the investment was oiled by cheap and available credit. Finally, and somewhat ironically in light of the free market, libertarian orientation of the energy-only model, Texas regulators made a series of administrative decisions relating to the wires function that would suppress energy prices, with the social costs of such policies uplifted to the transmission grid as fixed costs. In particular, Texas regulators adopted postage stamp rate-making for transmission, which, in combination with attractive credit, state renewable energy mandates and federal tax breaks, led to a stampede of wind investment in areas of the state where there was good wind but no load and insufficient transmission. In response to the resulting stranded investment in wind generation and electric wholesale prices in the western region of the state that were negative much of the time, regulators adopted the CREZ initiative, an ambitious, multibillion dollar build-out of transmission in “competitive renewable energy zones,” to transport the wind energy to load centers.

Now it appears the screw may have turned. In response to the build-out of efficient new generation, lower natural gas prices, and cheap wind energy, power generation investors face a hockey-stick shaped energy cost curve. Energy prices are cheap and flat for most hours of the year, but subject to dramatic spikes (for now limited by price caps) during relatively few scarcity periods. So long as the lights stay on, cheap energy is of course a good thing for customers, though because of wires-based social policies, stranded cost recoveries of above-market legacy generation, renewable energy incentives including the CREZ build-out, and storm cost securitizations, among other things, retail prices in Texas are not cheap, at least not yet, compared to other areas of the country. For investors, and especially those unable to use balance sheet financing, the flat and low cost supply stack would make it very difficult to justify new investment in Texas under the best of circumstances. But with the unavailability of long-term contracts and the more difficult access to capital markets due to lower risk appetites and tougher lending standards, not to mention political uncertainties, including federal tax and environmental policy, project financing of power plants has become very difficult indeed. Even for investors with access to balance sheet financing, the uncertainties of return due to the unavailability of long-term contracts make investment in generation very hard to square with internal company business models.

On top of these concerns, the Texas energy-only model has administrative add-ons that discourage investment and that are not in keeping with the laissez faire aspirations of the model. Among the most important of these are price caps that suppress prices during scarcity conditions. Obviously, facing competition and limited head room by virtue of a cheap, flat cost curve with the possibility of steep price spikes only during scarcity conditions, for investors these brief scarcity periods of potentially sharp price increases offer an opening, albeit fairly small, to raise revenues and recoup investment to offset the periods of low revenues and under-performance. With some controversy, and one commissioner abstaining, the Texas PUC raised the price caps some, from $3,000 MW/h to $4,500 MW/h, beginning August 1, 2012, and is currently debating raising price caps further as a way to incent investment. But for many investors, the increased price caps, though helpful, are also important indicators of regulatory risk. For them, given the tradition of political control over essential services such as electricity, the question is whether they are operating in a market with opportunities to prosper even if prices rise and markets turn volatile, as markets will do; or whether they are instead operating in a populist environment where laissez faire principles will be abandoned in the face of the inevitable destruction and discontinuities in the market that discipline investors and make markets efficient, but can rattle the public.

Beyond these matters, the debate in Texas now centers on whether the state should adopt an explicit and controlling reliability standard, and, if so, what market design principles and reforms are needed to achieve that standard. If a standard is adopted and it is based on the value of loss of load, the relationship between that administratively determined value of the loss of load and the amount of the price cap will be considered. In theory, the two should converge. Although it is universally accepted, however, that the value of loss of load is much lower for residential customers than for industrial customers, it appears that it is some industrial customers that are most heavily committed to comparatively low price caps, and residential customer advocacy groups most committed to administrative add-ons such as forward capacity markets. This cannot be reassuring for generation investors trying to ascertain whether they are operating in a market or in a political community.

Texas regulators are focused on the need for some fairly quick decisions about resource adequacy and market design. They know that for investors, recent returns in Texas have not been attractive. They also know that reserve margins are deteriorating due to retirements and relatively low new entry, combined with load growth at an average rate of 2.3 percent a year since 2002. In 2011, the planning reserve margin in ERCOT was about 14 percent, about equal to the 13.75 percent margin then considered necessary to support a 1-in-10 year reliability standard. But system reliability in 2011 was stressed by weather conditions at or beyond the range of possibilities that had been analyzed when establishing target reserve margins. In February 2011, an arctic weather event knocked out generation and caused load shedding in many areas of the state. And in the summer unprecedented heat, not seen since perhaps the 19th century, drove demand for electricity beyond anything expected, and caused operating margins to fall to single digits for long periods of time. The experience of 2011 established that reliability in Texas depends heavily on the weather, but the potential for weather extremes is greater perhaps than previously considered. ERCOT is currently considering updating its 13.75 percent target reserve margin based on updated weather data and the possibility of more extreme weather events, but it appears projected planning reserve margins are falling rapidly. A September 2012 ERCOT analysis indicates that, by calling on approximately 1900 MW of mothballed capacity, ERCOT may meet its target with a 14 percent reserve margin in 2014, but the reserve margin could fall to only 11 percent by 2015. Thereafter, load growth, potential retirements, and limited entry of new generation can be expected to depress reserve margins further absent a change in markets or market design. The year 2015 could pose a particular challenge, and especially if there are extreme weather events, because it may be approaching too quickly to add significant, difference-making new capacity resources.

The restructuring of the electric industry that former President and Governor George W. Bush introduced to Texas in the late 1990s successfully restructured the Texas market in a way that lowered energy prices and modernized the Texas generation fleet. More recent actions have resulted in Texas being a leader in the development of wind energy. But Texas stands at a crossroads, and there are more questions than answers about the right direction forward. What is the appropriate reliability standard for the electricity markets, and should the standard be a target or an administrative requirement? If a requirement, how will it be achieved? If only a target, how volatile and extreme is the potential market clearing price for electricity in an energy-only model, and what market add-ons, if any, are needed to incent generation investment or offset the operation of price caps? Finally, what is the likely public reaction to the resource adequacy issues that the state faces? Stay tuned: this could get interesting.