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. 

100 Megawatts Per Day: Solar Power on the Rise

By Nick Lawton, Staff Attorney

The International Energy Association (IEA) recently published an updated report on global deployment of solar power. The report, Technology Roadmap: Solar Photovoltaic Energy 2014 Edition, responds to significant acceleration in the solar power development by projecting that in 2050 solar power should generate 16% of the world’s energy. This blog post highlights key findings from the IEA report, assesses progress in the United States toward the IEA report’s goal, and recommends several measures that states and the federal government should take to promote U.S. leadership in solar development.

Dramatic reductions in the price of solar power and resulting accelerated solar development drove the IEA to substantially revise the Technology Roadmap for solar power that the agency had published in 2010. The IEA begins its report by noting the outstanding fact that the world has added more solar power in the last four years than in the prior forty. In 2013 alone, solar deployment proceeded at a remarkable rate of 100 megawatts per day. To put that number in perspective, the Solar Energy Industries Association (a U.S. trade association) calculates that on average 1 megawatt of solar power generates enough electricity to meet the needs of 164 U.S. homes. 100 megawatts of solar power is thus enough, on average, to power 16,400 U.S. homes. Especially considering that the American Council for an Energy-Efficient Economy ranks the United States 13th in energy efficiency (behind China and India), deploying enough power to satisfy 16,400 U.S. homes is not bad for a day’s work.

Yet despite this excellent progress, far more solar development is necessary for the world to reach the IEA’s goal of having 16% of the world’s energy come from solar power. In fact, the IEA notes that annual solar deployment will need to grow to an average of 124 gigawatts per year, which is roughly four times the pace of deployment in 2013. Fortunately, the IEA also notes that due to projected continuing decreases in the price of solar power, the annual average investment will only need to be twice the level it was in 2013.

Reaching this level of increased and sustained investment in solar power will require significant policy measures from nations around the world. Although solar power has already become cost-competitive in some markets, the IEA notes that in many regions policy support will be necessary to help solar power’s costs continue to decline, especially in markets where electricity prices do not internalize greenhouse gas emissions or other environmental harms.

The greatest single message in the IEA’s report is the call for stable policies to promote solar power (similar to the call I made in an earlier blog). Here, the United States falls quite short. For example, as I discussed several weeks ago, federal tax credits for renewable energy are short-lived, and their unpredictability leads to boom-and-bust development cycles. Meanwhile, U.S. states offer dramatically varying support for solar power, and for renewables more generally. Some states have ambitious programs, like California’s Renewable Portfolio Standard, or New Jersey’s requirement that builders of new homes offer to install solar power. Other states offer no incentives at all. The lack of stable, certain policies in the United States is likely one reason that the IEA reports that China and Japan outpace U.S. solar development. Similarly, Bloomberg News reports that less developed nations are developing renewable energy at twice the pace of wealthy nations like the United States. We can do better, and we should.

Nevertheless, there is cause for significant optimism as well. A projection by Deutsche Bank, as relayed by Bloomberg News, reveals that solar power will be cost-competitive in 47 U.S. states by 2016. This progress should drive dramatic new solar power development. Some movement is already underway. For example, Georgia Power, a subsidiary of the Southern Company (one of the largest owners of coal-fired power plants in the country) recently issued plans to develop solar power for army bases in Georgia. Southern Power has been expanding its solar holdings, now owning 338 MW of solar capacity. Duke Energy in North Carolina is on a similar track, recently investing in 278MW of solar capacity. Of course, this progress is a far cry from full achievement of the technical potential of solar power in the United States. For example, rooftop solar in Los Angeles could generate 19,000MW, dwarfing these utility investments. Nevertheless, the progress we are already making give us a strong foundation for future improvement and a strong cause for hope.