States Can Implement the Clean Power Plan Without Compromising Grid Reliability

By Amelia Schlusser, Staff Attorney

On December 9, the Federal Energy Regulatory Commission (FERC) announced that it will convene a series of technical conferences early next year to discuss whether EPA’s Clean Power Plan, as proposed, will threaten the reliability of the electricity grid. According to Energywire, FERC’s announcement was in response to electric industry stakeholder concerns that the proposed 111(d) rule will negatively impact grid reliability and wholesale electricity markets.

In November, the North American Electric Reliability Corporation (NERC) released a report addressing potential reliability implications associated with the proposed rule’s implementation. The report, which did not represent a “final and conclusive reliability assessment” of the proposed rule, called for a thorough analysis of the rule’s potential impacts on grid reliability. Unsurprisingly, NERC’s report triggered extensive outcry from industry groups and conservative lawmakers, opposing the rule’s implementation. The U.S. House of Representative’s Energy and Commerce Committee website claimed that NERC’s report “warned that the Obama administration’s power plant proposal would threaten the nation’s electric reliability.”

FERC subsequently decided to get involved to help ensure that state implementation of the Clean Power Plan’s requirements maintain grid reliability. FERC Chairman Cheryl LaFleur promoted the opportunity these technical conferences will provide to bring diverse stakeholders together, stating, “[FERC] clearly has a role to play in ensuring that the nation’s energy markets and infrastructure adapt to support compliance with the proposed Clean Power Plan.”

The concerns over the Clean Power Plan’s implications on grid reliability are both real and justified. The rule’s potential reliability impacts, however, are entirely surmountable. While the final rule will almost certainly encourage extensive retirements of inefficient coal-fired power plants, these retirements need not result in the “reliability crisis” many of the rule’s critics anticipate. Coal-fired power is not an essential component of a reliable electricity system. NREL’s Renewable Electricity Futures study concluded that we can feasibly integrate high levels of renewable energy onto the grid and could obtain 80% or more of our electricity from renewable sources by 2050. By investing in transmission system upgrades and optimizing grid flexibility, we can build a reliable, sustainable energy system devoid of coal-fired generation.

EPA’s proposed Clean Power Plan provides states with sufficient flexibility to upgrade their electricity systems without compromising grid reliability. The proposed rule encourages states to replace aging coal generation with renewable energy resources. While renewable energy sources such as wind or solar are variable, and thus not ideal baseload energy resources, states can implement a number of programs and policies to integrate this energy onto the grid without compromising reliability. For example, states can implement robust energy efficiency, energy storage, and demand response programs to offset electricity demand and alleviate reliability constraints. States can also improve grid operations by implementing intra-hour transmission scheduling and enabling dynamic transfers of variable generation between balancing areas. These practices enable states to obtain renewable energy from a broader geographic area and mitigate the impacts from localized weather events. For example, if a state confines all of its solar energy resources into one area, cloud cover in that area could threaten grid reliability. If the state instead develops solar energy resources in a variety of areas, cloud cover in one area would have minimal impact on the grid. The proposed Clean Power Plan’s flexible approach thus enables states to replace coal-fired power with renewable energy without compromising grid reliability.

Unfortunately, a number of states are independently limiting the flexibility the proposed rule would provide. According to ClimateWire, six states have already passed laws limiting regulators from implementing the final 111(d) rule “beyond the fence line” of their coal-fired power plants. In other words, these states can now only achieve compliance with their final 111(d) requirements by improving efficiency and decreasing emissions at their existing coal plants. These laws reflect the states’ opposition to the Clean Power Plan, but they also constrain their ability to implement the final rule without threatening grid reliability. Ultimately, if EPA finalizes a rule that sets emissions standards based on the beyond-the-fence-line approach and these states refuse to revise their new laws, these states may find themselves operating pursuant to a federal implementation plan that gives them even less flexibility.

The Clean Power Plan represents an important step in transitioning our national electricity system away from polluting fossil fuels. The proposed rule gives states flexibility to reduce emissions without compromising the reliability of the grid, and states should take full advantage of the flexibility the final rule may provide.

Utility Business Models Evolve Around Renewable Energy

By Nick Lawton, Staff Attorney

Two recent business developments on opposite sides of the world confirm that electric utilities are shaking up their business models in response to the rapid rise of renewable energy. Hawaii’s electric utility, the Hawaiian Electric Industries, recently struck a deal, estimated at $4.3 billion, to merge with NextEra Energy, Inc., a prominent, Florida-based renewable energy developer. Half a world away, German utility E.ON recently announced that it was splitting in two, forming one company to focus on renewable energy and another to continue managing fossil-fuel assets (primarily lignite, the dirtiest form of coal). Despite great physical distance between the electric utilities, there are strong parallels between their business developments. Each company has touted its development as a clear victory for renewable energy and a blow against climate change, but the reality for both is cloudier.

Bold Benefits for Renewable Energy?

Coverage of the utility moves has played up potential benefits for renewable energy development and climate change mitigation. For example, E&E News quotes Jim Robo, NextEra’s CEO, as saying that its merger with the Hawaiian utility is “about two leaders in clean and renewable energy joining forces to build a more affordable clean energy future.” Meanwhile, Eric Wesoff at Greentech Media writes of the merger as a “brilliant idea” that could transform the Hawaiian utility into a “renewable energy powerhouse.”  As for E.ON’s split into fossil fuel and renewable energy companies, Stefan Nicola at Bloomberg News writes that it “marks a watershed moment in Germany’s renewables effort that will likely bolster the country’s already leading position in clean energy.”

There is likely some merit to these claims. NextEra is purchasing a Hawaiian utility just as the state is considering a very broad transition away from fossil fuels and toward renewable energy, as my colleague Nate Larsen has discussed on this blog. Meanwhile, E.ON’s split is set against the backdrop of the German Energiewende, that nation’s ambitious transition from nuclear power to renewable energy. Both NextEra and E.ON’s new renewable energy arm should bring some valuable expertise toward managing these transitions. For example, NextEra claims to be the nation’s largest owner and operator of wind energy facilities and one of the largest generators of solar power as well. Proven experience making renewable energy work as a viable business could indeed help both Hawaii and Germany make a sustainable, affordable transition to renewable energy.

Or Business as Usual?

However, it is important to remember that utilities are capitalists, not environmentalists. Both companies are likely making these moves because they benefit corporate bottom lines, not because they benefit the global climate. For example, E&E News quotes the president of a Hawaiian solar company as noting that “NextEra would be buying HEI with the idea of making money, not doing the right thing to make this state some kind of renewable energy paradise.” The fact that NextEra is also the parent company of Florida Power and Light, a utility that has recently and successfully opposed energy efficiency and distributed solar power in Florida, provides a solid foundation for that suspicion. NextEra is likely pursuing new options in Hawaii because the market for renewable energy there is quite competitive with the high cost of importing fossil fuels. In short, NextEra is likely moving into Hawaii because it stands to make money there.

Meanwhile, E.ON is struggling to adapt to the fact that the German Energiewende has hit that nation’s utilities hard, with the price of shares in E.ON having fallen by 75% since 2010 and the utility’s revenues from fossil fuels dropping by a third. As Damian Khaya at Greenpeace reports, E.ON’s split likely has more to do with minimizing risks to its renewable energy efforts while simultaneously continuing its fossil fuel business. In fact, Mr. Khaya reports that E.ON’s new renewable energy arm will carry all the debt from the utility’s prior fossil-fuel activities, essentially subsidizing the new fossil-fuel arm’s reach into new territories (including a plan to build a new coal-fired power plant in Turkey). In short, E.ON’s split is a way to adapt to Germany’s new regulations while still making money from fossil fuels.

Renewable Energy as Utility Business Model

Nevertheless, despite my cynical look at the financial engines under the utilities’ hoods, I find some cause for optimism in the news about NextEra and E.ON. The world of regulated electric utilities has been in an uproar about renewable energy for some time now. At least six legal challenges have been raised against renewable portfolio standards, and more are looming on the political front, and U.S. utilities have been fretting about rooftop solar power throwing them into a death spiral. However, the recent moves by NextEra and E.ON. demonstrate that some utilities are starting to look toward renewable energy as a viable business model. As the purely economic case for renewable energy continues to become stronger, we should expect more utilities to move in this direction as well. And that, for me, is reason to hope.

We Can and Should Obtain 30% of Our Electricity from Wind Power by 2030

By Amelia Schlusser, Staff Attorney

A new report released by Environment Oregon’s Research and Policy Center calls for the U.S. to obtain 30% of our electricity from wind power by 2030. The report, titled More Wind, Less Warming: How American Wind Energy’s Rapid Growth Can Help Solve Global Warming, highlights wind power’s potential to reduce U.S. carbon emissions and help mitigate global climate change. According to Environment Oregon’s report, wind energy prevented 132 million metric tons of carbon dioxide from entering the atmosphere in 2013. If we succeed in procuring 30% of our electricity from wind power, Americans could prevent 705 million tons of CO₂ emissions per year by 2025 and 968 million tons per year by 2030. These reductions are equivalent to eliminating emissions from 254 coal-fired power plants in 2030, which represents a 40% reduction in power-sector emissions below 2005 levels.

Wind power has experienced tremendous growth over the past decade, and currently provides 4% of electricity in the United States. While we’ve made impressive progress in recent years, the deployment potential for new wind resources is incredible. Environment Oregon’s report emphasizes that it is both economically and technologically feasible to obtain 30% of our electricity from wind power by 2030. From an economic standpoint, wind power is currently cost competitive with natural gas-fired power in many parts of the country. As wind development has increased, costs have decreased—the levelized cost of new wind facilities decreased by 58% over the past five years. Wind power is also immune from potential price increases associated with fuel price volatility or emissions regulation, so wind power should become increasingly cost competitive over time. 

From a technical standpoint, the grid can support substantially more wind power than we currently transmit. Rapid wind energy deployment in parts of the country has shown that the grid is capable of integrating large quantities of wind power, and Iowa and South Dakota currently obtain more than 25% of their electricity from wind. According to NREL, there currently are no technical barriers to integrating 35% wind and solar power onto the grid. In a separate report, NREL determined that if we improve the performance, capacity, and flexibility of our existing electrical grid, we could obtain 80% of our electricity from renewable resources by 2050.

So what do we need to do to make the 30% wind power by 2030 goal a reality? Environment Oregon recommends that 1) EPA should strengthen and finalize its Clean Power Plan, and state implementation plans should maximize the use of renewable energy resources, such as wind power, to comply with their emission goals; 2) states should adopt ambitious renewable electricity standards mandating increased procurement of wind power; 3) state and federal agencies should work together to facilitate offshore wind power development; and 4) the federal government should renew and extend the Production Tax Credit (PTC) and Investment Tax Credit (ITC) to incentivize wind power development.

These policies would have a dramatic impact on wind power development in the United States. EPA’s proposed Clean Power Plan would encourage states to retire aging, inefficient coal plants, and replace these facilities with clean energy resources. State renewable electricity standards or renewable portfolio standards (RPSs) have already had a massive impact on wind development in a number of states, and a number of utilities cite their state RPS obligations as the primary driver of their planned wind capacity additions (see, for example, PacifiCorp’s 2013 IRP). Twenty-nine states currently have RPSs, but only California, Colorado, and Hawaii have set mandates of 30% or more. Many RPS requirements have already been met, and NREL doesn’t expect these standards to support more than one to three gigawatts (GW) of new wind development per year through 2020. Considering that nine states only have renewable energy goals and twelve states have neither renewable energy standards nor goals, there is room for significant policy advancement in this area. California, for example, already has one of the most ambitious RPSs in the nation, mandating that 33% of the state’s electricity come from renewable sources by 2020. Yet the California PUC will consider increasing this percentage through a rulemaking early next year. 

Finally, the federal PTC has provided a critical incentive for wind energy development and deployment in the U.S., and the tax credit’s 2013 expiration may prove devastating for the American wind energy industry (the House of Representatives is currently considering extending the PTC, but only for the remaining few weeks of 2014). NREL recently evaluated scenarios in which the PTC was either extended or allowed to expire, and found that if the PTC is not renewed, wind deployment will average between three and five GW per year through 2020, but if the tax credits are renewed, deployment will average between five and fifteen GW per year through 2020. 

Adopting and implementing these policy recommendations will put us on track to meet Environment Oregon’s goal of obtaining 30% of our electricity from wind power by 2030. This goal is realistic and achievable, and will help set us on a course towards a clean, sustainable energy future.

New York’s Proposal to Enhance Customer Engagement

By Nate Larsen, Energy Fellow

New York’s Department of Public Service (DPS) issued a straw proposal on April 24, 2014, detailing regulators’ recommendations for comprehensive electric industry reforms. The report, Reforming the Energy Vision (REV), described a number of measures that the state is considering, including the creation of Distributed System Platform Providers (DSPPs) to manage a distribution grid that will be expected to integrate increasing levels of distributed energy resources (DERs)—discussed in a previous post. The REV guidance also addresses the flip side of that issue, which is identifying opportunities to enhance customer engagement in the modern electric grid.

Customer participation is integral to the successful operation of New York’s model for the integrated grid of the future, both from a generation and a demand-side perspective. This post will address some of the DPS proposals to promote customer engagement outlined in the REV guidance.

Barriers to Customer Engagement

The REV identified six categories of barriers to the deployment of DERs, including 1) barriers to demand response; 2) barriers to distributed generation; 3) customer awareness; 4) access to data; 5) economic considerations; and 6) customer behavior patterns.

1.     Barriers to Demand Response

With regards to demand response (DR)—which allows certain loads to be curtailed during periods of peak demand—DPS found that customer-side incentives, bidding requirements, and customer aversion towards the risks inherent in adopting unfamiliar technologies were limiting factors in customer adoption of DR resources. The REV identified several other customer concerns that inhibit more widespread DR deployment, including the noncompliance penalty, the level of curtailment payments, short notice, an unclear value proposition for the customer, and a lack of information or understanding.

To overcome those obstacles, the REV suggested a review of the rates paid to DR resources to better reflect the value those resources provide to the grid. The guidance also recommended that DPS consider the implementation of a variable rate structure to better reflect the actual cost of power. DPS also notes that advancements in automated building systems have addressed some of those concerns.

2.     Barriers to Distributed Generation

The REV highlights a number of barriers to distributed generation (DG) deployment in New York, including 1) the fact that DG is not economically competitive with traditional utility service; 2) the onerous interconnection standards that potential DG customers face; 3) standby tariffs that unfavorably impact the customer value proposition; 4) a failure to account for all the benefits of DG to the grid; 5) the difficulty of obtaining financing for DG projects; 6) the responsibility of owning and maintaining equipment; 7) potential emissions restriction for combined heat and power resources; and 8) local code restrictions relating to some DG technologies.

3.     Customer Awareness

A lack of customer awareness regarding the potential value of DER is another obstacle identified by the DPS. The REV concluded that energy services providers typically targeted industrial and large commercial customers, resulting in limited opportunities for residential and small commercial customers to pursue demand-side management options. The report also identified customer confusion and lack of information as impacting potential customer engagement in DER development.

4.     Access to Data

Data access is important to the modern integrated distribution system to the extent that it allows electricity customers to manage their usage. The distribution model advanced by the DPS relies on the ability of customers to have access to their energy use data, understand the value of the data, and take advantage of goods and services that allow them to extract value from that data. Calling for an expansion of the availability of customer electricity usage, DPS was careful to note that such need for data access should be balanced against privacy protections, critical infrastructure information, trade secret protections and confidentiality requirements.

5.     Economic Considerations

Non-price economic factors represent another barrier to the widespread deployment of DERs. The high capital outlay, long payback period, and difficulty finding financing for DER projects make development unattractive for customers for whom those resources would otherwise be cost-effective. Those considerations are particularly limiting for low-income customers.

6.     Customer Behavior Patterns

Assuming that DERs are capable of presenting favorable economics, customers will only begin to adopt those technologies to the extent that they are easy to understand and use. DPS notes that programs designed to incentivize DERs should avoid requiring customers to make affirmative decisions to participate.

Opportunities to Facilitate Customer Engagement

Without going into many specifics, the REV also identified opportunities to promote DER deployment, including customer outreach regarding the benefits of DERs, regulations that encourage innovative business models, and the development of community resources. DPS also identified additional strategies to promote DER by resolving issues relating to data access, enabling DER technologies and removing financing barriers.

The guidance document additionally identified the potential for customer aggregation as an opportunity for DER development. DPS envisions that energy services companies (ESCOs) could play the role of aggregators, interfacing with both the DER-customers and the DSPPs. Those ESCOs would calculate the value of DER and compensate DER-customers for the services and product that they provide, while simultaneously marketing those products and services to the DSPPs.

In order to play the role envisioned by the DPS, ESCOs would need to move beyond their role as aggregators and develop new products and services to suit a new portfolio of varied customer requirements. Those products and services would range from traditional electricity service to demand management programs, dynamic pricing programs and ancillary services. The REV noted that many industrial customers are already taking advantage of a similar array of products and services.

DPS also addressed barriers to the role of ESCOs as proposed by REV, including the cost of acquiring new customers, current utility billing systems, access to customer energy usage information, access to distribution system constraints, and issues relating to servicing customers with small loads. To encourage the development of ESCOs as envisioned by the REV, DPS suggested that it would consider precluding utilities from offering energy commodity, instead requiring all customers to receive their energy services from an ESCO. DPS also noted that it would have to work to develop standards to ensure the reliability of the distribution system as ESCOs proliferate.

Conclusion

The REV reforms relating to customer engagement represent a significant departure from the passive electricity consumer model. While customers may continue to receive traditional bundled electricity service under the proposed reforms, they would also have access to an array of products and services that would encourage them to take advantage of distributed generation and demand-side management opportunities. Increased customer participation in the electricity system is an important component of the REV integrated grid model, and the success of the proposal will depend on the specific reforms that New York’s DPS ultimately promulgates.

Solar Consumer Protections: Necessary Regulation or Needless Cost?

By Nick Lawton, Staff Attorney

The solar industry in the United States has grown dramatically in recent years, but complaints from consumers are driving regulators to consider imposing new—and potentially costly—consumer protection measures. The industry should band together to guarantee integrity in solar business practices in order to keep costs down and business booming.

Solar Power’s Dramatic Growth

Solar power is increasingly mainstream. Costs have fallen dramatically, and the U.S. solar industry has set new records for development for each of the last several years. The pace of solar development is even faster in other countries, such as China, and in other less developed nations as well. Tom Werner, the President and CEO of SunPower, predicts that by 2035 solar power will be a $5 trillion industry. Despite the remarkable recent deployment rates for solar power, Mr. Werner argues that “[w]e’ve just scratched the surface of this opportunity.” And Mr. Werner is not alone. The International Energy Association projects that solar power could satisfy 16% of the world’s energy needs by 2050. And closer to home, Environment America recently released a report revealing that each U.S. state has the technical potential to generate more solar power than it consumes.

Some investor-owned utilities, which just last year decried solar power as a disruptive challenge to their business models, are participating more in the solar market as well. For example, Georgia Power and Duke Energy recently contracted to buy a total of more than 500 MW of solar power. On the other side of the country, Southern California Edison , recently announced plans to develop an integrated system of distributed solar and energy storage in order to reduce peak demand for energy in the Los Angeles area. Of course, investor-owned utilities in other parts of the country, such as Arizona and Wisconsin, are also spearheading challenges to the distributed solar business model by lobbying for greater charges for solar-powered homes. The different solar strategies of investor-owned utilities illustrate the fact that while solar power’s business case is increasingly robust, the policy framework for solar power is still a work in progress.

Customer Protection Concerns

An important recent solar policy debate revolves around the need for increased consumer protections for the solar industry’s customers. Recently, some in Arizona, Washington, and the U.S. House of Representatives have expressed concerns about the level of solar consumer protections. For example, one ratepayer advocacy organization in Arizona argued that some installers, including the prominent third-party installer Solar City, have offered consumers misleading information about the amount of money they could save through solar power.

Meanwhile, the Washington Utilities and Transportation Commission recently issued a report noting potentially significant consumer protection issues and describing the Commission’s limited jurisdiction over organizations like Solar City that offer third-party leasing of solar power systems. The report notes a “common consumer complaint” about fraudulent contracting practices in which homeowners are asked to sign what a salesperson says is an agreement to evaluate their home for solar, but which actually turns out to be a 20-year lease of solar panels. The report notes another “recurring accusation of deceit” about the amount of power solar panels produce and about likely utility rate increases. Additionally, the report identifies concerns about the quality of installed systems, inadequate disclosure of contract terms, and potential limitations on the sales of solar-powered homes.

Four Democrats from Arizona and Texas in the U.S. House of Representatives recently raised these important concerns with the U.S. Consumer Protection Financial Bureau. These representatives share Washington’s concerns that consumers may face deceptive or misleading claims about the financial viability of solar power systems leased from third parties.

Solar City has responded to the concerns raised in Washington state. Eric Weingarten, the general counsel for Solar City, acknowledged that there may be a need for some consumer protection regulations, but also warned against over-regulation and the development of a confusing patchwork of state regulations. Moreover, Mr. Weingarten noted that the solar industry is currently developing some standard business practices that could avert the need for government intervention.

Protecting Consumers or Raising Costs?

These concerns about consumer protection, though important, come at an awkward time for the solar industry. Solar power is just now becoming cost-competitive with other forms of energy in some jurisdictions. While falling costs have driven dramatic market growth, solar power has definitely not yet reached the U.S. Department of Energy’s goals for the industry under the SunShot Initiative. That initiative aims to reduce the cost of solar power to $0.06/kWh by 2020, which would make solar competitive with every other type of energy in all U.S. jurisdictions. The industry is not there yet, and the major remaining hurdle is the non-hardware, or “soft,” costs of solar power. If regulators decide that solar customers require additional protections, the resulting regulations are likely to impose another cost on the solar industry just when it is trying to streamline regulatory compliance and keep costs down.

The solar industry should do everything in its power to ensure that additional consumer protections are not necessary. The best way to achieve this goal is to actually make sure that consumers are getting fair deals that are fairly and adequately explained. For example, claims about solar energy production rates or likely increases in utility billing rates should be substantiated and easily verifiable. One good way to do this would be for the solar industry to have a website that hosts current, robust information about utility rates and solar productivity. Fraudulent practices should stop; no consumers should have cause to complain that they were misled into signing a long-term solar lease. Taking these common-sense steps could avert the need for costly consumer protection regulations. Failing to take these steps risks governments stepping in to impose new regulations, which would add to the costs of solar power just as the industry is becoming cost competitive. 

Will More Bad Investments Follow the Failed SONGS Upgrades?

by Melissa Powers, Director

On November 20, the California Public Utility Commission (CPUC) approved a settlement between California utilities and ratepayer advocates in which utilities will reimburse California ratepayers $1.45 billion for the failed upgrades to the San Onofre Nuclear Generating Station (SONGS). Ratepayers, however, will still end up paying about $3.3 billion for the replacement power and decommissioning costs for SONGS. One might wonder why either the utilities or ratepayer advocates would agree to this deal. However, when one considers the regulatory and constitutional implications of the SONGS failure, the compromise might indeed make sense for the parties involved. Nonetheless, the resolution highlights how ratepayers often end up on the hook for expensive and risky investments. It also may illustrate how risky investments may lead to further risky investments. Thus, the SONGS resolution should serve as a case study of why least-risk regulation and incremental investments are necessary in this era of profound change in the electricity sector. 

Background

In 2001, Southern California Edison (Edison) and San Diego Gas & Electric (SDG&E) sought CPUC authorization to upgrade two units at SONGS. The CPUC’s authorization to proceed came in the wake of the California electricity crisis, which may have convinced the CPUC that the state needed baseload power from nuclear plants to prevent future blackouts and power shortages. (Never mind that many analysts believe that California had plenty of power generation capacity during the crisis and primarily attribute the crisis to a poorly designed restructuring law and market manipulation.) With the CPUC’s authorization, the utilities set out to retrofit the aging nuclear plants, contracting with Mitsubishi Heavy Industries to perform the work.

During the retrofit process, it became clear that the SONGS upgrades had technical problems. The chosen retrofit technologies had never been tested in the size of the nuclear generators at SONGS. Although some observers (including a vice-president with Edison) voiced their concerns about the possible technological problems the project would face, the SONGS retrofits proceeded nonetheless.

And they failed. In fact, one unit failed after operating for less than one year, and the other lasted about two years. In mid-2013, the utilities closed the SONGS plant permanently. The utilities then asked the CPUC to bill their customers, not their shareholders, for the costs of the upgrades, other capital expenses, and replacement power.

Ratemaking and Failed Investments 101

In a typical industry, this type of failure would be an embarrassment, a huge economic loss for the company (unless it could recover contract damages from the contractor responsible for the upgrades, which the utilities are seeking to do), and possibly the start of bankruptcy proceedings. In the world of electric utilities, however, this type of failure typically spurs a lengthy regulatory process in which the utilities seek to recover expenses for failed investments from their customers.

There is a rationale behind compensating utilities for failed investments: in the world of regulated monopolies, captive customers depend on solvent companies to provide reliable electricity. If an electric utility becomes economically unstable, that utility may not be able to provide the service and future infrastructure upgrades customers need. Thus, even if a utility’s investment goes horribly wrong, the argument goes, customers should still pay for it so that the utility’s shareholders do not abandon the company, which could cause long-term harm to the customers.

This rationale came under heavy fire in the 1970s and 1980s, when investor-owned utilities sought to bill their customers for more than 100 failed nuclear power plant investments. Although several states had laws on the books that assigned the costs of failed investments to the utilities and their shareholders, state regulators nonetheless often required customers to pay at least a portion of the sunk costs of failed investments. Ratepayers were outraged by these decisions, and this outrage led to the development of integrated resource planning in many states, electricity restructuring that broke up vertically integrated monopolies in some states, and the passage of clearer laws making utilities fully financially responsible for their failed investments. California actually pursued all three strategies at different points.

In terms of paying for failed investments, California has a law that states, “the commission may eliminate consideration of the value of any portion of any electric . . . generation or production facility which, after having been placed in service, remains out of service for nine or more consecutive months, and may disallow any expenses related to that facility.” Moreover, if the CPUC finds that the unit retrofit costs resulted from “any unreasonable error or omission,” it “shall” disallow expenses. As a matter of regulatory law, the CPUC thus had authority to reject the utilities’ requests for compensation, particularly if it found the utilities acted unreasonably when retrofitting the units. In fact, the law—“the commission may . . . disallow any expenses related to that facility”—seems to give the CPUC discretion to reject compensation claims for the decommissioning costs. One might wonder, therefore, why CPUC and the ratepayer advocates would have agreed to the settlement terms. 

Two justifications likely explain their behavior. First, as discussed above, ratepayers may benefit by keeping shareholders happy. Indeed, Edison’s shareholders seemed relatively nonplussed by the settlement agreement, so Edison should have sufficient capital for further investments in electricity infrastructure. Second, had the CPUC and ratepayers not settled the case, the utilities might have been able to successfully litigate a takings claim.

The Takings Angle

Disputes about failed utility investments involve potential claims under the U.S. Constitution’s prohibition against taking private property without just compensation. In essence, utilities argue that their property has been taken when regulators fail to compensate the utilities for investments the regulators have themselves blessed. Takings law as it applies to regulated monopolies is somewhat unique, however. Courts must consider only the “end result” of a rate order, or how that order will affect the utility’s overall financial integrity and ability to attract investors. Under this doctrine, the Supreme Court itself upheld a rate order that denied utilities any repayment for their $45 million failed investment in nuclear plants, because the resulting loss would amount to less than 2.5% of each utility’s rate base.

Had the CPUC refused to bill ratepayers for any expenses associated with the SONGS retrofits or decommissioning, the utilities likely would have filed a takings claim. Indeed, Edison launched a media campaign in 2013, in which it argued that failure to reimburse the company for the plant would prevent the company from operating effectively. Whether the utilities would have been able to prove a takings claim is unclear, but the potential losses of $4.7 billion, with Edison’s share amounting to almost $3.7 billion, are much higher than other losses courts have forced utilities to bear. The risk of takings litigation thus may have motivated the ratepayer advocates to settle. (Interestingly, some consumers have filed their own lawsuit alleging the CPUC has illegally taken ratepayers’ property by forcing them to pay for failed investments.)

The Cycle of Risky Investments

While the SONGS settlement may make sense from a legal and practical standpoint, it also illustrates how failed investments can actually benefit utilities and even incentivize future bad investments. With SONGS offline, the utilities will need to obtain electricity from other sources, and they will earn a profit if they build new power plants and infrastructure to get that replacement power. Edison had already received authorization from the CPUC to build 1,000 MW of new natural gas generation before it developed its plan to build replacement power for SONGS. The CPUC has since granted both Edison and SDG&E authorization to build more natural gas plants; Edison may now add another 100 to 300 MW and SDG&E may add another 300 to 600 MW of power from any source, including natural gas, to make up for the lost SONGS generation. While both utilities must also get a significant amount of replacement power from energy storage and “preferred resources,” which include energy efficiency, demand response, and renewables, the CPUC has nonetheless authorized an additional 900 MW of natural gas to replace SONGS.

As my colleague, Amelia Schlusser, has written, least-risk planning might help mitigate over-investment in risky fossil fuel plants. Fossil fuel plants are especially risky today because they are typically built to operate for decades, but the energy system is experiencing unprecedented changes. Rather than invest in fossil fuels, utilities would be better off investing in renewables, distributed power, and energy storage systems, as Amory Lovins and others at the Rocky Mountain Institute argued 12 years ago in Small is Profitable. Although the CPUC seems to recognize the wisdom of this approach, it has yet to fully embrace it. Ultimately, by allowing California’s utilities to build new natural gas plants, the CPUC may prove, once again, that one bad decision often begets another in the world of electricity regulation.

We Must Discourage Electric Utilities from Making High-Risk Investments

By Amelia Schlusser, Staff Attorney

Ceres recently issued an update of its 2012 report, Practicing Risk-Aware Electricity Regulation. The updated report concludes that large fossil fuel and nuclear power plants are the riskiest investments for utilities, and that renewable energy, distributed generation, and energy efficiency are lower-risk investments with potentially lower price tags than baseload alternatives. According to Ceres, these relative investment risks are driven in part by recent developments in the U.S. electricity sector. Notably, the EPA is poised to regulate carbon emissions from new and existing power plants in the near future. In addition, renewable energy costs have decreased significantly in recent years, and some renewable technologies are either approaching or have already become cost-competitive with fossil fuel resources. Impending carbon regulations and increased deployment of distributed generation and energy efficiency are placing added pressure on entrenched utility business models, and, as GEI’s Nate Larsen recently discussed, regulators are beginning to explore strategies to modernize the grid.

Renewable energy resources such as onshore wind and solar PV are insulated from risks associated with fuel price volatility and emissions regulations, and the levelized costs of these resources are on par or below the levelized costs of fossil fuel resources. Nevertheless, many utility integrated resource plans continue to identify renewables as higher cost, higher risk resource options. For example, PacifiCorp’s 2013 IRP concluded that new wind resource additions were not cost effective. PacifiCorp also determined that a resource portfolio with extensive coal plant retirements or conversions represented both a high-cost and high-risk investment. PacifiCorp thus proposed to keep its coal fleet operating and only invest in new wind capacity if necessary to comply with state RPS requirements. Duke Energy Progress’s (DEP) 2013 IRP asserted that “[m]odernizing the power plant fleet is an important investment in the Carolinas’ environment and its future,” and noted that utility will need to invest in new incremental resources to compensate for future coal plant retirements. However, while DEP planned to procure enough renewable resources to comply with its RPS obligations, it determined that it should meet its future energy needs with new natural gas plants and nuclear resources.

The question of the day is whether EPA’s proposed Clean Power Plan emission goals will motivate utilities to adequately account for the risks and long-term costs associated with all fossil fuel resources. If so, the final 111(d) rule has the potential to incentivize investments in renewable energy. If not, the rule will likely encourage substantial investments in new natural gas plants and accompanying infrastructure, such as interstate pipelines. Realistically, the rule will likely result in construction of new natural gas generating units either on-site or in close proximity to existing coal plants or interstate transmission lines, and incremental deployment of renewable energy resources in the vicinity of existing transmission corridors. States, however, have the power to incentivize investments in less risky, more sustainable infrastructure through their 111(d) implementation plans. 

Clean Air Act section 111(d) directs states to establish “standards of performance” for emissions of covered pollutants from existing sources within a listed source category. Each state must draft a plan to implement and enforce these standards and submit its plan to EPA for approval. EPA’s 111(d) implementing regulations refer to these state-issued standards as “emission standards.” The federal regulations mandate that states establish these emission standards as either an allowable emissions rate or an emissions allowance system. The proposed 111(d) rule for carbon emissions gives states flexibility to comply with the rule’s requirements on an individual basis or enter into multi-state compliance agreements. If states prefer to implement their 111(d) emission standards through a state-based or multi-state allowance system, the proposed rule would enable them to establish a program that favors electricity generation from specific resource types. For example, state allowance systems could work in tandem with RPS requirements to incentivize renewable energy production.

A carbon emissions allowance program that places a premium on renewable energy generation is one potential strategy to deter investments in high-risk fossil fuel resources, but it is by no means the only available strategy. State public utility commissions should consider revising their resource planning and procurement rules to send a clear message to utilities that investments in baseload fossil fuel plants are not prudent and that zero-emitting resources are in the public interest. Ratepayer advocates should closely monitor levelized cost projections and oppose investments in resources that are vulnerable to long-term cost increases. And finally, policymakers should ensure that applicable legal and policy frameworks incentivize energy infrastructure development that mitigates ratepayer and taxpayer vulnerability to risk over extended timeframes. Infrastructure constructed today will likely operate for multiple decades, and it is imperative that we discourage investments that will lock-in exposure to rising costs and environmental degradation for years to come.