New York’s REV: Regulatory Reforms

By Nate Larsen, Energy Fellow

In its April 24, 2014 Reforming the Energy Vision (REV) straw proposal, the New York Department of Public Service (DPS) identified an array of comprehensive policy reforms geared toward facilitating distributed energy deployment in the state. DPS staff had three broad objectives in drafting its report: enable the modernization of the distribution system and create entities to manage that system; facilitate engagement by customers and third-party energy services companies; and revise the state’s ratemaking regulations to align with those policy goals. I discussed the proposals to create distribution system managers and engage customers and third-party energy services companies in previous posts. This post addresses the DPS staff’s proposed regulatory reforms discussed in the REV, which can be broken down into ratemaking reforms and rate design reforms.

Ratemaking: New York’s Current Model and Proposed Reforms

The traditional rate-of-return ratemaking model allows a utility to recoup expenses while earing a profit on the utility’s capital investments. In that model, a utility’s revenue requirement is set annually in a contested rate case before the public utilities commission. Traditional rate of return regulation ties utility profits to capital expenditures, and encourages utility resistance to non-utility owned distributed generation and efficiency. For that reason, the rate-of-return regulatory model in New York has evolved incrementally over the years from the traditional rate-of-return model to a new model incorporating modern policy goals.

           

New York’s current ratemaking model encourages multi-year rate plans, which allow a utility to benefit from improved efficiency. The model also uses negative incentives to adjust a utility’s revenue downward for failing to meet standards relating to outage duration, customer service, safety, etc. DPS staff recognized the need to adopt a more comprehensive approach to reforming the ratemaking model in order to achieve the state’s policy objectives. The New York DPS staff therefore proposed a variety of reforms to the state’s existing rate-of-return model, including 1) long-term rate plans, 2) outcome (or results-based) ratemaking, 3) symmetrical incentives, and 4) revenue decoupling mechanisms.

First, the REV includes a proposal to extend the rate plan period up to eight years. Long-term rate plans provide a degree of certainty, reduce expenses related to contested rate cases, and encourage a utility to find ways to reduce expenses. Long-term rate plans also benefit customers by including earnings sharing mechanisms, which require a utility to distribute a portion of its earning above the approved rate of return among its customers. The utility would also be required to meet certain standards in the first year of the rate plan—a so-called “gateway review”—in order to continue operating under the terms of that plan.

Second, the REV proposed outcome or results-based ratemaking. Rather than incentivizing the utility’s inputs, i.e. capital investments, outcome-based ratemaking would reward the utility for achieving targets designed to create long-term customer value. For example, those targets may be established in the context of resiliency, renewable energy integration, and carbon emissions reductions, among other categories.

Third, the REV proposed symmetrical incentives. These would establish positive incentives for a utility that provides high-quality service or otherwise achieves policy goals, while retaining some of the negative incentives designed to limit outage durations and discourage poor customer service and utility safety. The idea behind symmetrical incentives would be to provide the utility with a carrot for providing good service, in addition to the negative incentive stick.

Fourth, the REV includes a discussion of revenue decoupling mechanisms, which detach electricity sales volumes from utility revenue. Rather than basing a utility’s ability to earn its revenue requirement from electricity sales, a decoupling mechanism ties utility revenue to other components of the utility’s service. In so doing, decoupling removes the conflict between a utility’s need to earn a profit and policy goals that encourage distributed generation and energy efficiency. The REV, however, points out that while revenue decoupling mechanisms might remove a utility’s incentive to resist distributed generation and efficiency, they do not directly incentivize utility support of those resources.

DPS staff did not provide specifics regarding the outcomes it would promote, nor the types or level of incentives that it would consider in the REV. Instead, DPS staff allowed that it would work with stakeholders to make those decisions later in the reform process, with the next straw proposal expected to be released in the second quarter of 2015.

Rate Design: New York’s Current Model and Proposed Reforms

DPS staff recognized the need to reform New York’s rate design model to reflect its vision for the future of the distribution system. The REV contemplates a two-way transactive distribution grid, where the utility serves not only as the provider of electricity products and services, but also the purchaser and aggregator of customer-generated power and demand response capacity. Under that model, the distribution utility will essentially operate a market in which customers and third party energy services companies will both consume and provide discrete electricity products and services based on their needs.

New York utility customers generally pay bundled rates for their electricity. Those rates include the embedded costs of producing, balancing and delivering power based on peak demand. The REV ultimately envisions a new rate design regime, where individual utility products and services are unbundled and individually marketed based on customer needs. Allowing customers to pick and choose among utility products and services in a cost effective manner based on their system needs facilitates customer investment in distributed energy resources.

In addition to providing electricity services, the utility, as distribution manager, will purchase and aggregate the output of customers’ distributed energy resources. Rates for those customer-supplied products and services will need to reflect both their value to the grid in terms of resiliency, flexibility, low-carbon power, and avoided transmission costs, and their costs in terms of reserve capacity required to balance variable resources.  While DPS staff discussed the need for rate design reforms, it also stressed that those reforms should not impact customers’ access to universal service at reasonable rates.

The specific values and costs assigned to various distributed energy resources are uncertain, yet these costs will go a long way in determining customers’ value proposition in adopting those technologies. As is the case with ratemaking reforms, DPS staff will begin to flesh out the specifics of its rate design reforms with its Track Two proposal later this summer.

Conclusion

The REV provides a glimpse of how New York’s DPS staff envisions reforming the state’s ratemaking and rate design models. While the specifics of those reforms will ultimately determine their success in achieving the state’s policy objectives, it is encouraging to note that DPS staff appears committed to making sweeping changes to New York’s regulatory paradigm to facilitate the development of distributed energy resources.

Illinois & Maryland Consider RPS Expansion; Ohio Lags Behind

By Nick Lawton, Staff Attorney 

Legislators in Maryland and Illinois have proposed bills that would expand each state’s Renewable Portfolio Standard (RPS), substantially increasing the amount of renewable energy that utilities will have to build or buy in the next decades. These bills would both benefit the environment and grow the states’ economies by creating well-paid, green-collar jobs. In contrast, Ohio, which froze its RPS last year, has seen its jobs growth dwindle as a result. In short, state investments in renewable energy create jobs, and withdrawing support for renewable energy quashes jobs growth.

Maryland’s RPS-Doubling Bill

The Maryland Clean Energy Advancement Act of 2015 would double the state’s RPS on a quick timeline.  Currently, Maryland requires utilities to obtain 20% of their energy from renewables by 2022. Under the new bill, the utilities would need to obtain 40% renewable energy by 2025. Similarly, the bill would also double the RPS’s carve-out for solar power. Currently, solar power must contribute 2% of the state’s energy by 2022, while the new bill would require 4% by 2025.

The Maryland bill’s lead sponsor Sen. Brian J. Feldman (D-Montgomery) argues that the legislation is “a golden opportunity” for the state to develop “good paying jobs and a much needed boost to [the] economy.” Similarly, co-sponsor Delegate Bill Frick (D-Montgomery) notes that the state’s “solar industry is actually contributing more to our state than our iconic crabbing industry.” However, other legislators have expressed concern about possible compliance difficulties for utilities and increased costs for ratepayers. Delegate Frick has responded to those concerns by expressing willingness to amend the bill to more modestly require only 25% renewable energy by 2025.

The Maryland Department of Legislative Services has evaluated the bill’s fiscal impacts, which would fall primarily on ratepayers. Although it notes substantial uncertainties in its analysis, it projects annual compliance costs between $11 million and $ 44 million in 2018, rising to between $141 million and $566 million in 2025 and beyond. Translated onto utility bills, this would mean an increase of between $0.17 and $0.68 per month in 2018, and between $2.05 and $8.20 in 2025. The range in price increases has to do with Alternative Compliance Payments. If utilities fail to obtain sufficient renewable energy, they must instead pay into a state-managed fund. Alternative payments cost more than buying or building renewable energy. Thus, if utilities fail to comply through renewable energy development, their failure will cost the state’s ratepayers substantially. Moreover, the alternative payments do not necessarily create jobs in the way renewable energy development does. Thus, if this bill becomes law, Maryland’s utilities should make sure to invest in actual renewable energy development in order to limit rate increases and promote economic growth in the state.

Illinois’s RPS Expansion Bill

The Illinois Clean Jobs Bill has several goals. It would increase the state’s RPS, strengthen energy efficiency requirements, and call for the development of market-based strategies to reduce carbon emissions. The current RPS calls for utilities to obtain 25% renewable energy by 2025, while the new bill would require 35% renewable energy by 2030. Similarly, the bill would double the state’s energy efficiency requirements from 10% by 2025 to 20% by 2025. (The energy efficiency measure requires utilities to meet a portion of demand by reducing energy usage, for example through efficient appliances.) Finally, the bill requires the Illinois Environmental Protection Agency to develop a market-based means for compliance with the federal Clean Power Plan, seemingly focusing on a cap-and-trade system for CO₂ emissions.

The bill’s main sponsor, Senator Don Harmon (D-Oak Park), argues that “[t]here is no time to waste” in passing this bill, which would promote “new jobs, better health, and a cleaner environment.” Sen. Harmon notes that “[a]s strong as the clean energy economy is today, with 100,000 clean energy jobs throughout the state, Illinois is at a tipping point.” Co-sponsor Representative Elaine Nekritz (D-Buffalo Grove) also noted that “too many states are beginning to outpace” Illinois in renewable energy development. For example, the Sierra Club notes that in 2014 Oklahoma saw the development of more than 600 MW of wind energy, while Illinois saw none.

Although the state does not appear to have evaluated the bill’s rate impacts yet, the Illinois Science and Technology Institute reports that the bill would create roughly 32,000 new jobs in the state. Moreover, the bill carries forward an existing 2% limit on rate increases associated with the RPS. Thus, the bill would not increase rates more than 2%—but would also stop operating once the utilities hit that cap.

Ohio’s Dwindling Jobs Growth

Meanwhile, Ohio froze its RPS last year. Essentially, that measure meant that utilities would not have to take any further action toward RPS compliance until 2017. Nominally, Ohio’s RPS freeze was a ‘free-market’ move to avoid ‘picking winners and losers.’ In reality, those arguments have always been false, and the RPS freeze is really an effort to coddle the fossil fuel industry. Now, Ohio is seeing the first negative impacts from its move away from renewable energy. Ohio has slid from 8^th to 10^th place in terms of jobs in the solar industry. Although the state is still seeing jobs growth in the industry, that growth rate is slowing, and other states are leaping ahead. Andrea Luecke, president and executive director of the Solar Foundation, notes that Ohio’s RPS freeze may continue to lead to further declines in solar jobs in the state.

The Upshot: Renewable Energy Investments Create Jobs and Drive Economic Growth

The lesson is clear. Ohio froze renewable energy requirements and is losing its potential for clean-energy job growth. Illinois is considering a renewable energy mandate expansion that would expand clean energy jobs in the state by roughly a third. Meanwhile, California, a clean energy leader, has seen clean energy jobs grow more than four times as quickly as other states. Investments in renewable energy create jobs and drive state economies. Maryland and Illinois should pass their RPS-expansion bills, and other states should follow suit.

Closed-Loop Pumped Storage Can Support Grid Reliability During the Transition to a Renewably Powered Grid

By Amelia Schlusser, Staff Attorney

Tennessee Valley Authority's (TVA) Raccoon Mountain
pumped storage plant has a 1,652 MW capacity.

A Scientific American blog recently profiled the United States’ first energy storage plant. This so-called “ten-mile storage battery” was (and still is) a pumped-hydro energy storage plant operated by the Connecticut Electric Light and Power Company. The plant, which began operating in New Milford, Connecticut, in 1930, could generate up to 44,000 horsepower, which Scientific American’s Robert Fares deemed roughly equivalent to 33 megawatts of electricity. The pumped storage facility is still operational today.

According to Scientific American, pumped hydro is the most widely used form of energy storage in the U.S; in 2011, it provided 22 of the total 23 gigawatts of installed energy storage capacity in the country. And the technology has improved over the years, becoming larger and more efficient. Robert Fares reports that today’s largest pumped storage facility can generate up to 3,000 megawatts of electricity, which is roughly equivalent to the output of three nuclear generators.

Large-scale energy storage systems are more important today than ever. The energy mix in the U.S. is shifting away from dirty coal-fired power towards clean and sustainable renewable energy. Under EPA’s proposed Clean Power Plan, which aims to regulate carbon dioxide emissions from existing power plants under section 111(d) of the Clean Air Act, the shift from coal to clean power will continue to escalate in the next decade.

The transition away from coal will result in grid-wide reductions in baseload power resources and increases in variable power resources. The National Energy Regulatory Commission (NERC) released a report, titled Potential Reliability Impacts of EPA’s Proposed Clean Power Plan, which expressed concerns that changes to the energy resource mix under the rule could compromise the reliability of the U.S. power grid. NERC’s concerns draw from the fact that baseload resources inherently support the reliability and stability of the electrical grid. These resources can supply power to the grid when electricity demand is high and reduce their power generation when demand is low. Renewables, on the other hand, are variable energy resources, and the amount of power they send onto the grid fluctuates with the weather. Since grid operators must ensure that levels of power entering and leaving the grid remain in balance at all times, managing variable renewable resources can be a challenge.

The transition from coal to renewables, however, does not have to compromise the reliability of the grid.  The Brattle Group recently reviewed NERC’s Initial Reliability Review and concluded that the Clean Power Plan is compatible with maintaining grid reliability. The Brattle Group’s report, EPA’s Clean Power Plan and Reliability, which was prepared for the Advanced Energy Economy Institute, listed energy storage as one potential technological solution to the reliability issues raised by increasing penetrations of variable renewables.  NERC’s report also asserted that energy storage technologies could mitigate the reliability challenges presented by high levels of variable renewable power and argued that “their development should be expedited.”

TVA's Raccoon Mountain pumped storage facility is not
closed-loop, but the general design is comparable to a
closed-loop system.

Closed-loop pumped storage systems offer a promising technological solution for integrating high levels of variable renewable power onto the grid. These facilities consist of two or more reservoirs located at different elevations. When power supply exceeds demand on the grid, excess generation is used to pump water from the lower reservoir to the upper reservoir. When demand later exceeds power supply, water from the upper reservoir is released through hydroelectric turbines back into the lower reservoir. A closed-loop system cycles water between reservoirs without drawing from or discharging to external water supplies.

According to the Energy Information Administration, there are currently 40 pumped storage facilities in the U.S. However, these facilities are all more than 20 years old. Robert Fares at Scientific American noted that plans to construct six major pumped hydro facilities were canceled between 1986 and 2006, “mostly due to market uncertainty.” Developing a pumped storage facility can be an expensive and drawn-out process, and until relatively recently our fossil fuel-dependent energy sector didn’t require substantial energy storage capacities.

This dynamic is starting to change. The transition from coal to clean energy is making large-scale energy storage a viable and valuable alternative to new fossil fuel plants. A number of pumped storage facilities are currently in the works throughout the country. Absaroka Energy is developing two closed-loop pumped storage systems in Montana. The company’s 250 MW Coffin Butte facility and 400 MW Gordon Butte facility both received preliminary permits from the Federal Energy Regulatory Commission (FERC) and are starting to commence site feasibility studies. In Washington state, the Klickitat Public Utility District (PUD) is applying for a FERC license to construct a 1,200 MW closed-loop pumped storage system on a wind farm in the Columbia River Gorge. And in Oregon, EDF Renewable Energy is pursuing a 600 MW closed-loop storage system outside Klamath Falls. According to the National Hydropower Association, developers have proposed to construct 31 gigawatts of new pumped storage capacity in the U.S.

Only time will tell whether any of these proposed pumped storage systems will ever become operational. However, it’s becoming increasingly apparent that energy storage may be the key to integrating large quantities of variable renewable energy onto the grid. Regulators should consider incorporating closed-loop pumped storage into their 111(d) state implementation plans, and establish policies that incentivize energy storage development.

Coal-Fired Cost Overruns: Who Pays for the Pipe Dream of "Clean Coal"?

By Nick Lawton, Staff Attorney

Mississippi’s ratepayers are off the hook for billions of dollars in cost overruns at the long-delayed Kemper Power Plant, at least for the time being. The state Supreme Court has held that the Mississippi Public Services Commission (PSC) erred in allowing an 18% rate increase because the agency failed to evaluate whether Mississippi Power, the utility developing the power plant, incurred its costs “prudently.” The Court described the Commission’s failure to “balance the ratepayers’ interests with those of the utility” as resulting in a “grave injustice,” ordering the Commission to implement a refund for ratepayers.

I blogged recently about the cost overruns and delays at the Kemper power plant, which is a new type of coal-fired power plant that is supposed to prove the pipe dream of “clean coal” by demonstrating the economic viability of carbon capture and sequestration technology. Although the power plant will likely come online eventually, the demonstration of “clean coal’s” economic benefits has completely failed. The project, originally slated to cost roughly $2 billion, has now reached a total cost of more than three times as much. The total cost, of above $6 billion, is greater than the entire budget of the state of Mississippi, as the Mississippi Supreme Court noted. 

The essential question now is whether Mississippi’s ratepayers or the utility should pay for the increased costs. The PSC initially allowed the utility to pass those costs on to ratepayers, as I reported. However, the Supreme Court found that the PSC failed to consider whether the cost overruns were “prudent,” as state law requires. (States generally require regulators to consider whether costs are “prudent” before requiring ratepayers to shoulder them.) The upshot is that the utility may have to swallow these billions of dollars in cost overruns, offering ratepayers a refund for what they have already kicked in.

Or maybe not. The Mississippi Supreme Court ruled that the PSC erred by failing to consider prudency. But the court did not itself resolve the question of whether the utility incurred the costs prudently. The PSC could revisit this issue and could conclude later that the utility did in fact act prudently. If that happens, Mississippi’s ratepayers will once more be on the hook. In fact, the utility has already said that it plans to ask the Court to reconsider its ruling. The utility argues that if it can’t recover costs during construction, the rate increases will ultimately cost “significantly more,” roughly doubling the rate increase from 18% to 35%. Mississippi’s ratepayers should watch this issue closely.

Regardless of who pays and when, though, the moral of the story is the same. This coal-fired power plant has turned out to be far more expensive than expected. In fact, as the Mississippi Supreme Court noted, the Kemper power plant’s costs are now higher than the entire budget of the state of Mississippi for fiscal year 2014 or 2015. In short, this power plant—and coal-fired power generally—are a bad investment. In contrast, solar prices are down and solar employment is up. The time has come for all states—including those in the reluctant South—to transition to renewable energy.