Another Call to Reform the Regulatory Compact: the Interstate Renewable Energy Council (IREC)’s Five Suggestions for How to Integrate Distributed Resources into the Electricity Grid

By Kyra Hill, Energy Fellow

Regulators, policymakers, and academics are increasingly calling for a reform of what is known as the regulatory compact. Traditionally, through this compact, regulated monopolistic utilities provide power to customers at just and reasonable rates and in return earn a return on their investment for necessary capital expenditures. The need for reform stems from the fact that this structure results in overinvestment in expensive generation and transmission and underinvestment in distributed resources that are not typically owned by the utility—including residential renewable energy, energy efficiency, electric vehicles, energy storage, and demand response. These resources are integral to a renewable energy-based, resilient electricity grid, so figuring out a way to integrate them into the grid is critical. 

The Interstate Renewable Energy Council (IREC) recently released a report entitled “Easing the Transition to a More Distributed Electricity System.” The report advocates reforming the regulatory compact in a way that provides customers with more choice and access to clean energy, while allowing utilities to earn a return on investments like integration of distributed resources. As customers desire more of these resources, the report argues, regulators and utilities need to rethink how best to navigate—and where possible, eliminate—persistent hurdles. Some states—most notably New York, in its Reforming the Energy Vision (REV)— have started to comprehensively address these issues (a topic my colleague, Nate Larsen, writes about). As other states look to “reform their energy visions” in order to incorporate more distributed resources, they will benefit from the lessons of those that have already started the process.

IREC’s report helps to further the conversation by drawing upon efforts that states like New York, Hawaii, and Massachusetts have already begun. The report breaks down into five suggestions for regulators to consider. Major highlights include:

           

·      Performance-Based Cost Recovery

o   Steer revenue away from large, capital investments and towards distributed resources by instituting ratemaking based on “forward-looking” performance-based standards. These could include diversification of generation, carbon reductions, and third-party provider satisfaction (as opposed to traditional cost-of-service ratemaking).

o   Draw from existing performance-based ratemaking experiences, such as Illinois’ Energy Infrastructure Modernization Act and the United Kingdom’s Revenue using Incentives to deliver Innovation and Outputs program.

·      Customer-Value Driven Rate Design

o   Unbundle rates and offer creative packages of unbundled rate components. These generally include generation, distribution, transmission, customer service, and ancillary services, but could grow to include public health, job, and environmental benefits.

o   Build clear price signals into rate design based on actual analysis of where (and to which customers) benefits accrue.

o   Look at existing valuation studies (the Value of Solar process in Minnesota, the integrated demand-side management study in California, and the IREC handbook on costs and benefits of distributed generation).

·      Transparent and Proactive Strategic Planning  

o   Incorporate innovative goals within existing utility planning procedures. These goals could include referring infrastructure upgrade needs to a third-party bidding process in order to determine whether incorporation of distributed resources is cost-effective replacements to costly upgrades.

o   Require grid modernization plans (as in Massachusetts) or distribution resource plans (as in California).

·      Use Data Effectively

o   Make data available to third parties in order to better provide customers with the services they want (for example, energy choice and energy savings), while recognizing the need to maintain customer data privacy

o   Draw from existing data usage decisions (California). 

·      Update Interconnection Procedures

o   Eliminate major hurdles that require the entrant to shoulder the full cost of a necessary upgrade by developing a mechanism for cost-sharing (as California and Massachusetts have done).  

o   Take a “proactive approach,” as Hawaii has, enabling the utility to plan for distributed resource integration and ideally schedule integration where the system can incorporate it at lowest cost.

o   Using forward-thinking integration planning to incorporate shared renewable energy programs, such as community solar, which could have the added benefit of providing renewable energy to renters and low-income communities.

In short, IREC’s report acknowledges the need for regulatory changes and offers some useful models and suggestions for regulators and utilities to consider. Some of the suggestions, including unbundled rate design and effective data usage, will become easier to navigate as the value of distributed resources receives further study and data-sharing practices become better defined. In the immediate future, regulators should begin to implement forward-thinking planning processes, including revising interconnection procedures, grid modernization, and performance-based cost recovery, as these practices have the potential to create better, cleaner, and more resilient electricity grids. 

The Constitutional Implications of Oregon’s Coal to Clean Power Bill in Light of North Dakota v. Heydinger

By Amelia Schlusser, Staff Attorney

The Oregon legislature is currently considering a bill (introduced as SB 477 in the Senate and HB 2729 in the House of Representatives) that would prevent Oregon’s investor-owned utilities from selling self-generated coal-fired power to Oregon consumers after January 1, 2025. Last week’s post described the proposed legislation’s requirements and explained some of the bill’s practical implications.  I also noted that the bill raised some unanswered questions. The bill’s proponents explained that the introduced text is undergoing amendment to address these issues, which is a routine step in the legislative process. I also alluded to some potential legal implications associated with the bill’s distinction between utility-generated power and power sold on the wholesale market. This distinction helps ensure that the bill’s provisions comply with the Commerce Clause of the U.S. Constitution, which is the subject of this week’s post.

The Commerce Clause in Article I, Section 8 of the U.S. Constitution gives Congress authority to regulate interstate commerce. The negative corollary to this exclusive grant of federal authority is referred to as the “dormant” commerce clause. Under the dormant commerce clause (DCC), states may not enact laws or regulations that discriminate against or place an undue burden on interstate commerce. While states can enact laws that are necessary to protect the health, welfare, and safety of their citizens, these laws must not protect the economy of the enacting state at the expense of other states’ economies.

The Supreme Court has created a series of tests to determine whether state laws that discriminate or unduly burden interstate commerce violate the DCC. While these tests allow courts to give some level of consideration to state interests or purposes behind discriminatory regulations, the Supreme Court has held that state laws that regulate extraterritorially—regulating conduct beyond the enacting state’s borders—are per se invalid.

The Minnesota Decision

The federal district court in Minnesota recently issued a decision in North Dakota v. Heydinger, which involved a challenge to a Minnesota law that prohibited individuals from importing, committing to import, or entering into a long-term contract to purchase electricity that would increase power sector carbon dioxide emissions in Minnesota. The State of North Dakota, coal companies, and multi-state electricity providers challenged the Minnesota law, arguing that it violated the dormant commerce clause. The district court agreed and held that the law was per se invalid because it had an extraterritorial reach and regulated commerce that takes place entirely outside of Minnesota.

The district court determined that the Minnesota law applied to “power and capacity transactions occurring wholly outside of Minnesota’s borders” in violation of the dormant commerce clause. The court’s conclusion was premised primarily on the fact that Minnesota’s power grid is managed and operated by the Midcontinent Independent System Operator (MISO). Within the MISO territory, electricity generators from throughout the multi-state region sell power onto the grid, and electricity providers purchase power from the grid. The district court determined that this market-based grid system does not recognize state boundaries and cannot differentiate between power entering the grid in one state and leaving the grid in another. Therefore, the court reasoned, a non-Minnesota utility could inject electricity in the grid outside of Minnesota with the intent to sell this power to consumers outside of Minnesota, but this power could still end up in Minnesota and contribute to power sector CO₂ emissions in the state.  In the district court’s eyes, because a North Dakota generator could not guarantee that the coal power it injected into the MISO grid would not enter Minnesota, it would presumably be forced to adjust its non-Minnesota business practices to comply with Minnesota’s law.

Implications for Oregon SB 477 and HB 2729

The Minnesota district court’s decision is currently under appeal in the federal Court of Appeals for the Eighth Circuit, and while it’s difficult to predict exactly how the appellate court will rule, it’s entirely possible that the lower court’s decision will be overturned. Nevertheless, Oregon’s SB 477/HB 2729 was clearly written to avoid North Dakota v. Heydinger’s outcome. First, the bill only applies to investor-owned utilities (IOUs) operating in Oregon, so non-Oregon utilities are not subject to the bill’s requirements. Second, the bill explicitly exempts “market purchases of unspecified power” from the bill’s reach, so coal power generators outside of Oregon can still sell their power on the wholesale market without violating Oregon’s no-coal mandate. Finally, the bill directs Oregon’s IOUs to “reduce the allocation” of coal-fired power to zero by 2025, which indicates that IOUs operating both inside and outside of Oregon can still sell their coal-fired power to non-Oregon consumers.

These provisions should help the bill avoid the legal outcome that Minnesota’s law faced at the district court level. However, the Minnesota decision only addressed that law’s extraterritorial reach; because the district court determined Minnesota’s law was per se invalid under the DCC, it didn’t consider whether the law was discriminatory against out-of-state interests or whether it imposed an undue burden on interstate commerce. A full analysis of applicable DCC case law is beyond the scope of this blog entry. Nonetheless, it’s reassuring that the bill’s drafters appeared to recognize the potential Commerce Clause implications and took efforts to minimize the proposed legislation’s vulnerability to a constitutional challenge. 

Colorado Senate Republicans Attack the State's Renewable Portfolio Standard

By Nick Lawton, Staff Attorney

Colorado has joined the fray over the fate of Renewable Portfolio Standards (RPSs). On Thursday, February 5, Republicans in the Colorado Senate passed a bill that would substantially erode renewable energy requirements for both investor-owned utilities (IOUs) and rural electric cooperatives. Although likely to fail in Colorado’s Democrat-led House, the bill offers yet another demonstration of the poor political theater behind the opposition to renewable energy—echoing repeal efforts in West Virginia and several other states.

Colorado was the first state to enact an RPS by popular demand through a ballot initiative in 2004. Initially, the RPS applied only to IOUs and required only 10% of their energy to come from renewable resources by 2020. However, the Colorado legislature has expanded the RPS several times. It first doubled the renewable energy requirement in 2007 and also imposed a 10% renewable energy requirement on rural electric cooperatives. In 2010, the legislature again expanded the requirement for IOUs to the current level of 30%. Finally, in 2013, the legislature doubled the requirement for cooperatives to the current level of 20%. Each amendment left the compliance date of 2020 intact.

Now, Republicans in the Colorado Senate have passed a bill along party lines to reduce renewable energy requirements by 25% for cooperatives and 50% for IOUs. Thus, both cooperatives and utilities would need to obtain only 15% of their energy from renewables by 2020.

As Tessa Cheek at the Colorado Independent has reported, the debate about the RPS has proceeded among predictable party lines. Nominally, Colorado Senate Republicans are aiming to keep electricity rates low, especially for rural communities. Senator Ray Scott (R.-Grand Junction) argues that the RPS burdens consumers, while Senator Tim Neville (R.-Littleton) argues that the RPS has caused Colorado’s electricity rates to swell from among the cheapest to among the most expensive in the West. Colorado’s Democrats disagree. Senator John Kefalas (D.-Fort Collins) notes that renewable energy has led his district to enjoy some of the state’s lowest energy rates. Similarly, Senator Matt Jones (D.-Boulder) argues that “it’s critical to keep [the RPS] because renewables are a job creator and cheaper.” Senator Jones noted that utilities in Colorado have chosen to build wind farms because they are cheaper than fossil fuel-fired power plants.

The bill’s main sponsor, Senator Scott, continues to peddle a fundamentally flawed argument against the RPS. I blogged recently about Senator Scott’s lofty-sounding but vapid argument that ratepayers should not be on the hook for renewable energy, which ignores the fact that ratepayers ultimately fund all utility investments, whether renewable or not. Now, E&E News quotes another misleading argument from Senator Scott: “If it's a great business model, go out and build yourself a nice wind farm [without tax breaks and alternative energy requirements]. Do what everyone else does, come back to the open market and say, 'Hey, I've got power for sale.'" Two fatal flaws plague Senator Scott's sound bite. First, the argument that renewable energy should not receive subsidies ignores the facts. All energy sources have received subsidies, and the subsidies for oil and gas have dwarfed the subsidies for renewables. The following chart of historical average annual subsidies from a report by DBL Investors, a venture capital company, aptly illustrates the point: on an average basis, fossil fuels have received far more money in subsidies each year than renewables have.

Second, and more fundamentally, there is no such thing as an “open market” for electricity in Colorado. Utility purchases of electricity—which of course ratepayers ultimately pay for—are tightly regulated. Utility investments are either regulated by the Public Utilities Commission or through arrangements under the Public Utility Regulatory Policy Act, a federal law. Either way, the choices about how to generate electricity are government choices; the electricity market is not an “open market.” Rescinding or weakening an RPS will not make the electricity market free; such a move would only guarantee that the state's electricity remains dirty. 

As for Colorado’s utilities, Colorado’s rural electric cooperatives do not favor the Republican repeal effort. A recent editorial by Kent Singer, executive director of the Colorado Rural Electric Association, notes that “we are not advocating a reduction of the ‘20 percent by 2020’ requirement.” The cooperatives have proposed their own bill, which would eliminate a distributed generation requirement, but it would not reduce the overall amount of renewable energy required. Meanwhile, IOUs are on track to meet existing requirements. For example, Xcel Energy reports that it is “ahead of compliance in all categories of the RES (Retail DG, Wholesale DG, and non-DG) and will be able to meet the 2014 RES without additional generation acquisitions.”

Because Colorado’s RPS thus seems to be working, the likeliest explanation for the party-line RPS reduction effort is politics. Colorado’s Senate Republicans appear to believe that opposition to renewable energy will help bolster their political fates. This calculation appears consistent with the repeal of West Virginia’s RPS. However, opposing renewable energy remains bad politics. For example, a 2013 nation-wide survey of Republicans revealed that 77% supported renewable energy, and that 70% of those in support of renewables believed we should develop them “immediately.” More locally, a 2014 survey of Colorado’s voters revealed that 76% would be more likely to vote for a candidate who promotes renewable energy. With numbers like those, it would seem that opposition to renewable energy is likely to backfire.

Coal to Clean Power: The Oregon Legislature Considers a Bill to Replace Coal-fired Electricity Generation With Clean Energy

By Amelia Schlusser, Staff Attorney

The Oregon legislature is currently considering a bill that aims to reduce the generation and

PGE and PacifiCorp own shares in the Colstrip
Generating Station, a coal-fired power plant in Montana  

use of coal-fired electricity in the state and replace coal with clean energy by 2025. The bill’s sponsors, Senator Chris Edwards and Representative Tobias Read, introduced the proposed legislation as S.B. 477 in the Oregon Senate and H.B. 2729 in the Oregon House of Representatives. The introduced bill requires an “electric company” to “(a) Reduce the allocation of electricity from coal-derived generating resources to zero on or before January 1, 2025; and (b) Replace those coal-derived generating resources with clean energy.” This post discusses the bill’s applicability and specific requirements.

The Bill’s Applicability and Primary Mandate

The bill applies to electric companies that sell power to Oregon consumers. However, many electricity providers in Oregon don’t qualify as “electric companies” under Oregon law. The introduced bill uses the existing definition of the term found in ORS 757.600, which defines “electric company” as “an entity engaged in the business of distributing electricity to retail electricity consumers in this state, but does not include a consumer-owned utility.” In other words, the bill only applies to Oregon’s investor-owned utilities (IOUs), including PGE, Pacific Power, and Idaho Power. It does not apply to consumer-owned utilities, including municipal electric utilities, public utility districts, or rural electric cooperatives.

So under the introduced bill, Oregon’s three investor-owned utilities (IOUs) must “[r]educe the allocation of electricity from coal-derived generating resources to zero on or before January 1, 2025.” But what does this mean? Each of the IOUs operating in Oregon (PGE, Pacific Power, and Idaho Power) own or partially own coal-fired generating resources. Presumably a portion of the power from these plants is “allocated” to the utilities’ customers in Oregon. The bill requires these utilities to “reallocate” their coal-fired power to their customers outside of Oregon. In other words, the bill prohibits the IOUs from selling the coal-fired power they generate to Oregon consumers after January 1, 2025.

However, the bill “[d]oes not apply to market purchases of unspecified power.” This presumably means that the bill’s requirements don’t apply to wholesale sales of coal-fired power from third party generators to IOUs selling power in Oregon’s retail market. In other words, Oregon’s IOUs could still purchase coal-fired power on the wholesale market and sell that power to Oregon consumers. This distinction has legal significance, because the Federal Energy Regulatory Commission (FERC) has exclusive jurisdiction over wholesale electricity markets and the Commerce Clause of the U.S. Constitution restricts states’ from regulating commercial activity outside of their borders. I will explore this issue further in a later post. For now, I think it’s important to note that the bill would not create a total barrier to coal-fired power consumption in Oregon.

The Bill’s Secondary Mandate: Replace Coal-fired Power With Clean Energy

The bill ultimately requires Oregon’s investor-owned utilities (IOUs) to stop allocating (i.e. selling) electricity they generate from coal to Oregon consumers by 2025. In the meantime, the bill requires the Oregon Public Utility Commission (PUC) to direct the IOUs to “develop a least-cost plan” to reduce their allocations of coal-fired power. These plans must include “a comprehensive accounting” of the utilities’ coal-fired generating resources. Plans must also include an analysis of the costs each coal-fired power plant will incur over the remainder of the plant’s useful life and an analysis of whether a coal-fired power plant will become “uneconomical before the end of the plant’s useful life.” In addition, utility plans must include a “least-cost, least-risk analysis of the order in which the electric company will reallocate electricity generated by [coal-fired power] plants.” This presumably means that each IOU must evaluate different options for reducing sales of coal-fired power in Oregon and replacing that lost generation with power from other, “cleaner” resources, while minimizing costs and risks to ratepayers.

In addition to producing a “least-cost plan” to reallocate their coal-fired power, the bill directs each IOU to “identify the quantity and type of supply-side and demand-side resources that will replace the coal-derived generating resources.” The utility then must “identify the least-cost method of achieving a mix of energy resources that is at least 90 percent cleaner than the coal-derived generating resources being replaced.” So each IOU must determine which resources are available to replace their coal-fired generation, and identify the combination of resources capable of replacing coal power at the lowest cost to consumers. These replacement resources must be “at least 90 percent cleaner” than the coal-fired resources they replace. In addition, utilities must “give preference to resources that allow electricity to be transmitted to this state on a real-time basis without shaping, storage or integration services,” so long as the resource is not more expensive or less reliable than alternative resources. This means that utilities may only replace their coal-fired generation with variable renewable resources, such as wind and solar power, if these variable resource options are less costly than other options and do not compromise the reliability of the grid.

Unanswered Questions

The bill, as introduced, aims to achieve an important and admirable objective. Coal-fired power pollutes our air and water, emits more carbon dioxide than any other source in the U.S., and destroys our national landscape. Oregon’s proposed legislation strives to protect our air, land, water, and climate by eliminating this resource from the state’s energy supply. While this is a commendable goal, the proposed bill creates some significant questions. First, it does not define “90 percent cleaner,” and this ambiguity could leave the bill vulnerable to legal challenge if it becomes law. Second, the bill explicitly disfavors replacing coal-fired power with a combination of wind or solar power and energy storage. Given the bill’s least-cost resource mandate, this preference for non-variable resources is a little befuddling. And finally, the bill would repeal Oregon’s existing greenhouse gas emission standards for investor-owned utilities, which limit carbon dioxide emissions from all generating resources, including natural gas plants.

In addition to these textual ambiguities, the bill raises some interesting legal questions regarding state energy regulation. I’ll explore these issues in greater detail in next week’s post.

Investments in Renewable Energy Pay Off

By Nick Lawton, Staff Attorney

States that invest in renewable energy are seeing strong returns, while those that cling to older methods of generating electricity are falling behind. As the price of renewable energy continues to plummet, this pattern is only likely to perpetuate.

California offers an excellent example of how renewable energy can yield economic benefits. California leads the nation in terms of the sheer amount of installed and operating renewable energy, according to the National Renewable Energy Laboratory’s 2013 Renewable Energy Data Book. Bloomberg Business now reports that “California’s bet on green energy is paying off, with clean technology companies creating more jobs and investing more money than competitors in any other state.” In fact, stocks in California’s clean energy businesses are projected to grow more than twice as quickly as those in other states. Moreover, California’s clean energy job market has grown more than four times as quickly as in other states. Bloomberg Business ties both trends directly to California’s strong policies supporting renewable energy.

Hopefully, the strong economic returns from renewable energy will bolster the political prospects of California increasing its Renewable Portfolio Standard. Governor Jerry Brown announced his intention to have half of the state’s energy come from renewable resources by 2050 in his recent inaugural address. Now, California Assemblyman Eduardo Garcia (D-Coachella) has proposed a “Clean Energy Act” that would turn Governor Brown’s proposal into law. Interestingly, the proposed Clean Energy Act would focus on non-intermittent renewable resources—which can generate electricity 24 hours a day—such as concentrated solar power or geothermal power. Additionally, the proposed law may increase the market for energy storage—another field in which California is already a leader, with the nation’s first energy storage procurement mandate for utilities. These new requirements for renewable energy and energy storage will poise California to continue to lead the nation toward a future powered by renewable energy, and will likely yield great economic benefits for the Golden State along the way.

Meanwhile, states that continue to rely on older energy generation technologies are not seeing the kinds of economic benefits that California has seen. I reported recently that states that have no renewable energy requirements face average increases in electricity rates comparable to states with Renewable Portfolio Standards—and that some rate increases from upgrading fossil fuel-fired power plants outstrip the rate impacts from renewables.

Recent news from Mississippi and Georgia confirms that clinging to fossil fuels and nuclear power is incredibly costly. The Southern Company, a utility that serves several southern states, has been working on a massive new coal-fired power plant in Kemper County, Mississippi since 2010. That plant is still under construction and has cost more than twice as much as originally projected. The current price tag is a whopping $6.1 billion. Even when the plant was slated to cost only $4.7 billion in September 2013, the plant would still have been “one of the most expensive power plants ever built for the amount of electricity it will produce,” according to a Sierra Club spokesman quoted in Bloomberg Business. The result has been rate increases of 15%, roughly 5 times the national average. This plant was supposed to prove that “clean coal” was affordable and realistic; what it has actually proven is that clinging to coal costs ratepayers far more than investing in renewables.

A similar lesson comes from Georgia Power’s $14 billion Vogtle nuclear power plant. That plant is also over-budget and overdue. In fact, according to the Southern Alliance for Clean Energy (SACE), the project is “more than three years delayed and the total project costs are at least $4 billion over-budget.” SACE is currently engaged in a legal battle with Georgia Power over how much of the project’s costs should be borne by ratepayers, and when. Georgia law allows the utility to recover costs and earn profit even before the power plant comes online, meaning that Georgia’s citizens are paying the tab before they see any power. In effect, as SACE argues, Georgia’s ratepayers “were forced to pay early for this multibillion-dollar project and are carrying all the risk, while the company’s shareholders are getting all the profit.” The effect on rates has been similar to the effect from the Kemper coal plant, with rates for Georgia Power’s customers rising between 6 and 12 percent—between twice and four times the national average.

In stark contrast to the delays and cost overruns associated with coal and nuclear power in Mississippi and Georgia, those states that have enacted Renewable Portfolio Standards are overwhelmingly on track to meet their targets on time and with much less significant rate impacts, less than 3% in the vast majority of states. The lesson seems clear. Clinging to outmoded energy sources costs ratepayers, but investments in renewable energy pay off.