IOUs Under Pressure


Policy and technology changes are re-shaping the utility business model.

Fortnightly Magazine - June 2009

Electric utilities are at the confluence of once-in-a-lifetime economic, technology and regulatory forces that will, over time, re-shape the utility business model.

The demonstrable need for massive investment in electricity delivery infrastructure, along with the construction of new, clean production technologies, presages enormous cost pressures on ratepayers—and the utilities that serve them. These pressures, if acknowledged at all, are given short shrift in current discussions, largely because the full ramifications of added delivery investment and production cost increases will not be apparent for a number of years. Other factors conspiring to hinder discussion include the political clamor for immediate job creation (or at least retention), continued uncertainty around major elements of energy and regulatory policy (e.g., climate-change legislation, carbon pricing, renewable energy standards), extremely tight credit and capital markets, and the anticipated, but always difficult to predict, impact of technology development.

An assumption of stasis, though, is difficult to reconcile with the pronouncements of many knowledgeable observers who believe the industry is, and will continue to undergo, change on an unprecedented scale. If so, why would the current utility model be immune from such changes? The new shape of utilities remains unknown, but change on a significant scale seems inevitable—and that change will present as many challenges as opportunities.

Rising Costs

The historic—and to date largely successful—investor-owned utility business model reimburses utilities’ operating costs and virtually guarantees returns on capital investments, in exchange for providing reliable and economic service to customers at regulated rates. But this model will be subject to increasing and continuous stress as operating costs rise and the magnitude of capital investments increases.

The need for increased investment in grid infrastructure, smart-grid technology, and a more diversified and renewable supply portfolio is taken as a given. To the extent there’s any debate, it’s associated with such issues as the magnitude of capital required, cost allocation, and timing (i.e., which projects, and which type of projects, come first).

Significantly less attention is paid to the associated long-term cost impacts to ratepayers (and taxpayers). Or, if attention is directed at costs, the discussion typically becomes so muddled with conflicting or inconsistent estimates, trends and impact assessments that definitive answers seem unobtainable. And that’s not surprising, for a number of reasons.

First, numbers bandied about as to needed investment in the industry over the next two decades are so large—some estimates run into the trillions of dollars—that a reasonable frame of reference is difficult to construct. What does it mean to ratepayers or taxpayers to spend that much money? How much is being spent now? Second, while much needs to be done, funds being requested now won’t have significant immediate ratepayer impact. No single utility is asking for regulatory benediction to immediately spend a trillion dollars. Third, and directly related to the second reason, no single utility ever will request approval to spend a trillion dollars. Given the balkanized nature of the U.S. electricity industry (i.e., 50 state jurisdictions, multiple federal agencies, numerous regional transmission organizations, public interest groups, etc.), requests for rate relief will come piecemeal, over time and, individually, will not appear too onerous. Finally, the price impact of these enormous expenditures might be mitigated to some as-yet-unknown degree by offsetting reductions in prices, due to increased energy efficiency, load shifting, and better utilization of delivery infrastructure. But while the impact to ratepayers will be diluted—one rate case at a time—it will add up.

What might the total impact be? The Edison Foundation recently released a report, Transforming America’s Power Industry: The Investment Challenge 2010-2030, which included a finding that the U.S. electric utility industry by 2030 will need to make a total infrastructure investment of $1.5 trillion to $2 trillion. Excluding generation investments, the total ranges from $0.9 trillion to $1.1 trillion,1 or approximately $50 billion per year. By way of reference, EEI estimates 2009 industry-wide transmission- and distribution-related capital expenditures of about $32 billion.2

The revenue requirement impact of such an investment is imprecise at best, but on an annual basis will include standard cost elements of O&M, taxes, and a return of, and on, the investment. This could equate to rate increases of 5 percent or more per year based on 2008 revenues from retail sales of electricity totaling about $350 billion.3 And these rate increases are exclusive of the production cost impacts that will accompany changes in the nation’s supply portfolio as the industry and technology go green.4 And what of future supply costs? The estimated costs of providing electricity through increasingly green and renewable supply portfolios are as numerous as there are pundits and special interest groups (see Figure 15). While the range of such estimates is wide, the trend is for continued closing of the cost gap between renewable and conventional technologies. Renewable technologies will continue to decline in costs as technology advances increase efficiencies and larger production volumes decrease unit costs.

For example, according to the U.S. Department of Energy, photovoltaic capital costs will decline from $7,500 per kilowatt in 1995 to less than $1,000/kW by 2020. But the $1,000/kW hurdle already might have been met since panel manufacturer FirstSolar recently announced a panel manufacturing cost reduction to $980/kW. Photovoltaic technologies aren’t the only examples of reduced costs and increased efficiencies. Biomass technologies are expected to a reach a similar $1,000/kW installed cost (down from more than $2,000 in 1995). Geothermal and wind energy tell similar stories, with rapid, non-linear declines in cost (see Figure 2). And these trends (as of late 2005) are apparent well before the recent influx of attention and funds from the federal government.

Simultaneously, conventional technologies (e.g., coal, gas and nuclear) have, and will continue to experience, upward cost pressures due to the imposition of external environmental costs—namely carbon controls or purchased credits—as well as construction commodity cost increases, and the deployment of new, technologically advanced facilities. Nuclear plants seem particularly susceptible: FPL concluded in late 2007 that two new 1,100 MW units could cost between $5,500 and $8,100 per installed kilowatt.6 And partially lost in the noise of discussion on renewable energy sources is the impact of carbon pricing on the operating costs of existing fossil-fueled facilities. Naturally, the impact depends on the price of carbon and the facility type, but with approximately 50 percent of U.S. generation supplied by coal-fired units, the impact could be significant. Moody’s recently estimated that carbon regulations could cause power prices to increase between 15 percent and 30 percent, assuming a CO2 cost of $20/ton.7 And the impact is likely to be disproportionate depending on geography and fuel mix. So while the cost gap between renewable and conventional technologies may be narrowing, supply costs will be rising along with delivery charges.

The investor-owned utility business model has its roots in the creation and management of a scale-based monopolistic industry, which fueled the 20th century conversion to electric power. To date, the underlying major technologies—coal-fired, gas-fired and nuclear facilities—have supported this model. However, this could change rapidly as new technologies, operational characteristics and economics are introduced. Many of the new energy technologies do not conform easily to a scale-based business model. Optimal capacity is smaller and the economics are dramatically different, as are the grid requirements. In fact, the industry search for utility-scale new generation technology deployment might be little more than a costly attempt to jam a square peg into a pre-conceived (or institutionally comfortable) round hole. A common sense example: Wind and photovoltaic facilities in good locations have a 20 percent to 30 percent utilization factor. Increasing the size of such a facility to say, 200 MW (i.e., utility scale) dramatically increases the size of a variable and non-dispatchable asset. On the other hand, a portfolio of smaller facilities, diversified across fuel sources and operationally integrated (through a smart grid) can provide reliable and consistent generation. The investor-owned utility, as currently configured, might not be well-equipped to deploy such a model. Market forces could choose to bypass them and create a network of self-generating entities, wherein the utility is increasingly needed for stand-by and system reliability capabilities, creating very different challenges and opportunities.

Change is Accelerating

Utilities are not renowned as incubators of change. Generally they’re managed as conservative, low risk businesses. Utilities don’t lead the way in the development or deployment of new technologies. R&D functions, if extant in a utility, are primarily geared around monitoring, supporting and underwriting industry organizations that undertake research for groups of companies. Given the critical nature of electricity, new technologies are introduced only after careful testing and usually in limited applications. There’s no reward provided for being first to market with any development; in fact, there is more downside risk to any new technology introduction than upside benefit. Industry history, therefore, is one of careful and slow change.

EES North America

At the same time, by many measures, the pace of technological change and importantly, the rate of adoption of change is accelerating (see Figure 3). The meaning is clear: Technology is more rapidly assimilated today than in the past and will be more rapidly assimilated in the future than today. Industrial and energy-related technologies are not immune from these forces. Advances in distributed generation technologies such as photovoltaic arrays, fuel cells, wind power, batteries, and other more exotic supply sources continue to show dramatic improvements in cost and efficiency. The same is true for grid-related technologies, such as advanced sensors, distributed computing, high-speed two-way communications and smart meters. In some ways, the message is as frightening as it is impressive. What happens to companies when technology development and deployment outpace an existing industry’s ability to keep up?

The demise of electric utilities isn’t at hand. The service provided is too critical and the existing infrastructure too expansive for any technology development to quickly overturn the status quo. But change in the telecommunications industry serves as a reasonable proxy. It has been over 25 years since the landmark decision to unbundle AT&T, the original telecommunications utility, into seven regional operating companies (plus a long-distance company) that were essentially providing local and regional landline services. Now, the landline business is dying, the cell phone industry has exploded and may yet be supplanted by voice over internet protocol (VOIP) technology, and most of the regional operating companies have been acquired, merged or sold. The telecommunications landscape is vastly different from what it was 10 years ago, let alone 25 years ago.

Arguably there’s no single disruptive technology on the horizon in the electric utility industry, akin to cellular service, that will serve as the catalyst for dramatic change. But that’s not required. The industry is characterized by the simultaneous emergence of several technologies (and regulatory and legislative initiatives), each of which can create incremental change that collectively can cause an industry disruption. And with the government prepared to invest billions of dollars in renewable and distributed generation (DG) technologies over the coming years, and regulatory, tax, and environmental policies poised to dramatically impact the industry, it would be surprising only if such changes didn’t materialize.

Recent history on under-performing utility stocks provides some guidance as to investor perception of future utility value. A recent article8 reviewed trends in utility share prices. The article noted that investors penalized utilities that had cash-flow and liquidity constraints, un-competitive market positions and contentious regulatory relationships. While these negatives might be self-evident to utility executives, this is exactly the environment to which the utility business could be headed, regardless of business-cycle considerations. The overall industry trends point to a combination of all three factors. Even the most conservative regulated utilities may not escape pressure on enterprise value.

Shifting Preferences

Rate base rate-of-return regulation will not disappear, but the current usage-based model that rewards increased energy sales almost certainly will. In the short-term, utilities will be under increased financial pressure as electricity sales are projected to decline 1.7 percent in 2009 following a 0.7 percent decline in 2008.9 In the long-term, the impact of the emphasis on energy efficiency, as well as increased penetration of distributed generation technologies, is sure to strain a usage-based model. And distribution planning—and accompanying capital expenditures—will be complicated further by new and not easily forecasted changes in load and network design to allow for changing system conditions. Utilities and regulators in several jurisdictions are pursuing solutions, such as rate decoupling, that guarantee utilities a return on their investment irrespective of demand. Such approaches have merit, but rate decoupling is less a matter of cost control than cost distribution. It doesn’t address the more fundamental issue associated with an ever-increasing cost base requiring continuing support by customers who might have alternatives, or at least might desire them. Either way, alternatives will exist.

The pace of change across many related fronts—technological, social, and regulatory—will create demand for change that utilities might struggle to meet. For example, a smarter grid is smarter because it provides more knowledge about real-time grid conditions and, presumably, allows operators to take nearly instantaneous actions. This will increase data flow by orders of magnitude. The management of this data is essentially an information technology (IT) issue. Regional Transmission Organizations (RTOs), such as PJM, are effectively large IT houses and can be assumed to be equipped to adapt to the massive change in data flow at the transmission level. But RTOs do not manage or control distribution systems, which are likely to see an even greater need for data-management capabilities as DG becomes more widely deployed and millions of smart meters are installed at residences and commercial entities. To position themselves to handle these new data-management requirements, utilities will be challenged to adapt their skill sets, recruiting tactics, resource base and even their cultural temperament to pursue IT as a core competency.

Politicians and analysts predict the transition to a smart grid and a green power system will bring fundamental change. Can there be any doubt that utilities will be profoundly affected? Many questions present themselves. For example, if a smart grid becomes a reality, can reliability or power quality be localized and priced accordingly? As the costs of renewable and DG technologies decline, what’s the appropriate rate structure for a customer requiring limited delivery or backup-only service? Will utilities in deregulated markets be allowed to own generation connected at the distribution level, and to what degree? How will third-party competitive entities be treated? How will customer interactions and relationships change? What will be the disruptive technologies? Are utilities prepared to develop and deploy cutting-edge IT systems?

Whatever the questions and whatever the answers, it seems increasingly clear that the utility of today will be dramatically reshaped in the coming years. But with challenges come opportunities.

The investor-owned utility business model is not immediately threatened, but it will come under pressure. Cost increases necessitated by grid reinforcement and enhancement, widespread implementation of smart-grid technology, imposition of environmental externalities, and increased supply costs from renewable technologies will, over time, put a massive strain on utilities’ ability to increase customer rates. Customers will look for alternatives, and alternatives will be there. The arc of increasing efficiency and declining cost, present in so many other areas, will not bypass the energy industry, particularly given the current focus on energy-related technologies and the political and social momentum behind energy efficiency, green technologies, and energy independence. Importantly, the pressure for change doesn’t have to be widespread. Change at the margins from customers with the ability and willingness to change will be sufficient to serve as the catalyst.

Utility management, not surprisingly, is accustomed to strategic challenges imposed by legislative or regulatory fiat—i.e., industry deregulation, emissions controls and renewable portfolio standards. But signs point toward market and technology forces providing significant additional impetus toward reshaping the delivery landscape and damping steady increases in transmission and distribution revenue streams.

Change is not necessarily synonymous with deterioration, financial or otherwise. Utilities can do many things to position themselves for success, including: taking a more active and leading role in technology development; making a long-term commitment to becoming IT centers of excellence; rethinking the regulatory compact; offering new, innovative products and services developed with third-party assistance; partnering with numerous, cutting-edge technology companies to better understand technology trends and impacts; enhancing their presence and relationships with key customers; and undertaking the long, but important process of culture change.

There are no easily identifiable or well-trod paths to the future. But as General Shinseki, former U.S. Army Chief of Staff, is reported once to have said, “If you don’t like change, you’re going to like irrelevance even less.”



1. Transforming America’s Power Industry: The Investment Challenge: 2010—2030; The Edison Foundation, November 2008, pg. xiv.

2. EEI 2007 Financial Review—Plus 2008 Developments.

3. Energy Information Agency (EIA):

4. The Edison Foundation report notes that a direct link between higher investment costs and rate changes is not clear until fuel costs and other expenses are included. The report notes that under certain scenarios, fuel, and presumably supply costs, could be lower. Even if certain fuel cost elements in the supply portfolio decline (e.g., wind and solar), however, capital cost recovery will still represent a significant cost element.

5. Renewable Energy Data Book; U.S. Department of Energy, September 2008, p.13.

6. Direct Testimony and Exhibits of Steven D. Scroggs on behalf of Florida Power & Light in Docket No. 07-0650; October 2007

7. Moody’s: Risks of CO2 regulation moving closer for power sector; SNL, March 19, 2009.

8. Miller, Jeffrey et al., “Goodbye Safe Haven,” Fortnightly, March 2009.

9. Energy Information Agency: