The Clean Power Plan and Grid Reliability: Fostering the Transition to a Modernized Transmission System

By Amelia Schlusser, Staff Attorney

The debate over the potential impacts of EPA’s proposed Clean Power Plan on grid reliability is gaining steam. Critics contend that the proposed rule calls for hasty and drastic changes to the nation’s electricity resource mix, which will result in widespread retirements of coal-fired power plants and increased deployment of renewable resources. The reliability debate centers around the fact that baseload resources, such as coal plants, provide stable and predictable electricity, while renewable resources, such as wind and solar power, provide variable and intermittent power. Therefore, the argument goes, replacing coal plants with variable renewable resources may jeopardize the reliability of the electrical grid.

The reliability debate first made headlines following the release of the National Energy Reliability Corporation’s (NERC) Initial Reliability Review of the Clean Power Plan, which voiced concerns that the rule could compromise the reliability of the power grid. NERC’s report recently made headlines for a different reason. According to Greenwire, the Energy and Policy Institute recently criticized NERC for failing to disclose that Energy Ventures Analysis, a contractor that worked on the NERC report, had ties to a coal technology company. However, there is little evidence that this potential conflict of interest actually influenced NERC’s findings regarding reliability impacts.

Meanwhile, politicians, regulators, and industry representatives are becoming increasingly vocal on the potential reliability impacts of the Clean Power Plan. On March 11, regulators from Wisconsin, Wyoming, and Indiana told the U.S. Senate Environment and Public Works Committee that the proposed rule would threaten grid reliability in their states. According to Greenwire’s coverage of the committee meeting, the commissioner of the Indiana Department of Environmental Management, Thomas Easterly, noted that he was very concerned “that we will see some catastrophic results somewhere in the implementation of this plan.” Senator Jim Inhofe (R-Okla.) also argued that the rule would threaten the reliability of the grid. Jeff Burleson, Vice President of System Planning at Southern Company, recently issued a statement asserting that the Clean Power Plan will jeopardize grid reliability.  Burleson claimed that the rule would “potentially put serious reliability and operational pressures on the grid,” and that “it does so under the guise of ‘environmental compliance’.”

NRDC’s John Moore argues that the reliability argument is a bluff intended to reduce utility compliance obligations under the Clean Power Plan. Moore’s blog specifically focuses on Southern Company’s claim that the rule will jeopardize grid reliability, which is not the first time the utility has made this argument in response to new environmental regulations. Moore points out that in 2011 Southern Company argued that EPA’s mercury and air toxics standards would cause “numerous rolling blackouts” starting in 2015. In 2014, however, the company stated that it was 98% in compliance with the standards, and as of 2015, the rolling blackouts have failed to materialize. 

It’s unclear whether the Clean Power Plan’s critics are intentionally crying wolf by asserting that the rule is incompatible with the reliable delivery of electricity. However, it is clear that these reliability challengers are failing to fully consider available technologies and strategies that utilities and grid operators have successfully implemented to maintain reliability under high penetrations of renewable generation.

The reliability challengers are also overlooking the energy sector’s ability to develop innovative solutions to respond to grid reliability constraints. Utilities are investing in smart grid improvements and other technologies to facilitate integrating renewable energy onto their systems. For example, one of my previous posts discussed how Idaho Power Company developed and implemented a new forecasting tool that has improved the utility’s ability to integrate wind energy onto the grid at a cost savings of approximately $100,000 a month.

Grid operators throughout the nation are also developing strategies to integrate increasing amounts of renewable energy onto the grid without impacting reliability. For example, Columbia Grid and Northern Tier Transmission Group initiated a Wind Integration Study Team, which in turn created a Dynamic Transfer Capability Task Force to assess the potential impacts of increasing dynamic transfers of electricity between balancing areas to integrate variable renewables and maintain grid reliability. And a recent report by Navigant Research estimated that utilities would spend $107 billion through 2023 on “synchophasors and wider-area situational awareness systems” which enable grid operators to collect and transmit data and rapidly identify grid disturbances before outages occur. These innovative grid improvements help maintain reliability and functionality, and according to the North American Synchophasor Initiative, these technologies provide significant benefits for integrating intermittent renewable resources.

These examples describe only a few of the countless efforts to improve and modernize our national grid systems to accommodate the evolving U.S. energy mix. These efforts help to demonstrate the electricity sector’s ability to proactively address emerging system constraints and develop innovative strategies to maintain grid reliability. Once finalized, the Clean Power Plan will shift the composition of the electricity generating mix in the country. However, this shift will be supported by the deployment of advanced grid technologies and innovative operational strategies that will ultimately improve the functionality of the grid and help facilitate the transition to a clean, sustainable energy system.  

Michigan Mulls Energy Options

By Nick Lawton, Staff Attorney

Michigan’s legislature, led by Republicans in both chambers, is considering several bills that would alter the state’s Renewable Portfolio Standard (RPS). A Republican bill in the state House of Representatives would expand the RPS’s definition of “renewable” to include municipal waste, scrap tires, and unsustainably harvested woody biomass. Another Republican proposal (not yet formally introduced) in the state Senate would eliminate the RPS altogether, moving the state toward a utility-led, cost-driven planning process. In contrast, Democrats in the House and Senate aim to double the RPS.

Currently, Michigan’s RPS requires the state’s utilities to produce or procure 10% renewable energy by 2015. According to the Michigan Public Service Commission, utilities are on track to comply. In other words, Michigan is poised to meet its renewable energy goals. However, those goals are among the lowest in the nation. Most states with an RPS have a target of at least 20% renewable energy. Thus, the Michigan Democrats’ goal of doubling the existing RPS would put the state in line with most other states that have similar policies.

In contrast, Republican Senator Mike Nofs’ proposal to eliminate the RPS would place Michigan among the minority of states that lack an RPS. In lieu of a renewable energy mandate, Sen. Nofs’ proposal would set emissions standards for various pollutants from the electricity sector and then require an unspecified percentage of generators to meet those standards. Renewables would gain extra credit toward this unspecified percentage and could remain eligible for other existing incentives. Additionally, Sen. Nofs’ proposal would rescind Michigan’s targets for energy efficiency.

A separate bill from Republican Representative Aric Nesbitt would allow municipal waste, scrap tires, and woody biomass to count as renewable energy under the RPS. The current RPS counts woody biomass as “renewable” if it is “derived from sustainably managed forests or procurement systems,” but Rep. Nesbitt’s proposal would eliminate that requirement. (Additionally, Rep. Nesbitt’s proposal would rescind Michigan’s deregulation of the electricity market, instead moving the state back to a fully regulated system in which utilities are guaranteed the authority to sell power to 100% of the consumers in their territories.)

In stark contrast to these Republican proposals, Democrats in the Michigan House and Senate have proposed doubling the RPS to require 20% renewable energy by 2022. The Democrats’ proposal would give the state the same 7-year period of time to reach the new target as the original RPS did. Additionally, the Democrats’ proposal would aim to keep costs in check by limiting utilities’ ability to impose special surcharges. Finally, the Democrats’ proposal would expand the state’s energy efficiency goals as well.

Expanding the RPS is a good idea for Michigan for several reasons. First, by complying with the existing RPS, Michigan’s utilities have already shown that they can obtain a 10% increase in renewable energy in a 7-year window, which is exactly what the RPS expansion would require. Second, as Democratic lawmakers Senator Hoon-Yung Hopgood and Representative Bill LaVoy note, the existing RPS has attracted nearly $ 2.9 billion in renewable energy investment to the state. Expanding the RPS could draw similar sums over the next seven years. Third, Michigan ranks fourth in the nation for clean energy job growth, according to a new report by Environmental Entrepreneurs. That group’s executive director notes that to continue growing jobs, governments need to support clean energy, not quash it. Expanding the state’s RPS would provide a mechanism for Michigan to continue its strong trend in developing clean energy jobs.

Finally, despite the fact that both Republican bills in Michigan would erode or eliminate the state’s RPS, renewable energy does enjoy support from conservatives. Indeed, the Michigan Conservative Energy Forum’s executive director Larry Ward opposed the Republican proposals, stating that the state “can and must be bolder” on energy efficiency. Although he stops short of advocating expansion of the RPS, Mr. Ward has said, “It would be really nice to continue making progress on the use of more efficiency and renewables and our economic impact studies show the advantage of that.”

Given the clear benefits of renewable energy and broad political support, Michigan should adopt the proposal to expand its RPS. The expansion would bring economic and environmental benefits and would help Michigan’s renewable energy industry become increasingly competitive.

Coal States Pass Laws Limiting Regulatory Authority to Implement the Federal Clean Power Plan

By Amelia Schlusser, Staff Attorney

The Mount Storm Power Station, a 1,600 MW coal plant in
West Virginia 

The Environmental Protection Agency’s (EPA) proposed Clean Power Plan aims to reduce carbon dioxide emissions from existing power plants 30% below 2012 levels by 2030. The Agency issued the draft rule, which implements section 111(d) of the Clean Air Act, in June of 2014, and is expected to issue a final rule in July of 2015. A number of states are currently considering bills that would limit their regulatory agencies’ abilities to implement EPA’s final rule, and Kentucky and West Virginia have both adopted legislation to that effect. While these laws represent the states’ opposition to federal greenhouse gas controls, they could ultimately expose these states to greater federal oversight under the Clean Air Act.

State Clean Power Plan Legislation

Last year, Kentucky passed House Bill 388, which limits the kinds of emission reduction activities the state can impose on its coal and natural gas plants. The law mandates that standards of performance for coal and natural gas plants consist of measures that can be executed at the generating units, and cannot include switching to or co-firing with other fuels or limiting operations at affected plants. The law also includes a provision authorizing state regulators to adopt performance standards that are less stringent than the federal standards established by EPA, if any generating unit-specific factors “make application of a less stringent performance standard or longer compliance schedule more reasonable.”

Greenwire reported that Kentucky regulators hope to comply with the final 111(d) rule through emission reductions resulting from planned coal plant retirements. According to Greenwire, Kentucky’s Energy and Environment Secretary Leonard Peters asserted that the plant closures, which were already slated to retire over the next 15 years, should enable the state to comply with the federal rule without violating Kentucky’s legislation. The state’s two major investor-owned utilities—Louisville Gas & Electric and Kentucky Utilities Company (both owned by PPL)— approved this regulatory approach.

West Virginia recently adopted legislation limiting the state’s Department of Environmental Protection’s (DEP) authority to create a 111(d) implementation plan and submit such a plan to EPA for approval. This new law directs the DEP to conduct a study assessing the “feasibility” of implementing a final 111(d) rule in West Virginia and submit a report on the Department’s findings to the state legislature. If the DEP determines implementation is feasible, it must create an implementation plan and submit it to the legislature. The legislature may then authorize the department to submit the plan to EPA or direct the DEP to amend the plan and submit the revised plan to EPA. The law also allows the legislature to revoke the DEP’s authority to create or implement the Department’s proposed plan. And like Kentucky’s legislation, West Virginia’s law restricts regulators from adopting beyond-the-fenceline emission reduction measures.

ALEC’s Influence

These state laws appear to be heavily influenced by a conservative organization working to protect fossil fuel industry interests. In December, Climatewire reported that the American Legislative Exchange Council (ALEC) introduced model legislation that would require state regulators to obtain legislative approval for proposed 111(d) implementation plans. Kentucky’s legislation was inspired by ALEC (Greenwire, March 4).  According to Climatewire, West Virginia’s law was also based on ALEC’s model legislation.

ALEC is a conservative organization that aims to advance libertarian policies at the state and national levels. According to the group’s website, ALEC creates and promotes policies that support limited government, free market ideals, and federalism. The group views EPA’s attempts to regulate greenhouse gas emissions as a threat to these conservative principles, and challenging the proposed 111(d) rule is therefore “incredibly important” to the organization. ALEC’s policy proposals also aim to advance the interests of its corporate membership, which may help explain the group’s preference for adversarial rhetoric (for example, ALEC’s carries out its 111(d) work under the “EPA’s Regulatory Train Wreck” initiative).

ALEC’s model legislation has received a warm reception in a number of conservative-run state legislatures. According to Climatewire, legislators in Arizona, Kansas, Mississippi, Missouri, Oklahoma and Tennessee have introduced bills based on ALEC’s model policy, and “Arkansas' Senate recently approved a bill mirroring ALEC's language.”

These state legislatures presumably introduced ALEC-influenced policies in an attempt to protect their existing energy industries. However, ALEC’s model legislation will ultimately constrain states’ abilities to implement the final 111(d) rule’s requirements. EPA’s proposed rule provides states with flexibility to adopt a combination of strategies to reduce power sector emissions. For example, if a state’s coal plants have already achieved maximum efficiencies, the state can comply with the rule by deploying additional renewable resources or adopting energy efficiency measures. Kentucky’s and West Virginia’s legislation prevent regulators from adopting flexible compliance approaches by prohibiting beyond-the-fenceline emission reduction measures. These limitations may make it difficult for the states to achieve compliance with the rule’s emission targets.

States that adopt ALEC’s model legislation also risk exposing themselves to heightened federal oversight. ALEC’s model requires approval from both legislative branches before regulators can submit a state implementation plan to EPA for approval. This legislative approval will likely be difficult to obtain from lawmakers who have limited energy-related knowledge or experience and intense political motivations. If a state fails to submit an implementation plan to EPA, section 111(d) of the Clean Air Act authorizes the Agency to issue a federal implementation plan for the state. This federal implementation plan will presumably include standardized or generic emission reduction measures that may not account for the state’s specific or unique circumstances.

Other states should consider these implications before blindly following ALEC’s advise or following in Kentucky’s or West Virginia’s footsteps. States ultimately are obligated to comply with federal law, and states that proactively develop well-designed plans will be better equipped to implement EPA’s final rule. States that instead prefer to bury their heads in the sand will suffer the consequences.

Solar Power in California: Large or Small?

By Nick Lawton, Staff Attorney

As California ponders an increase to its Renewable Portfolio Standard, which would require the state’s utilities to obtain 50% renewable energy by 2050, a set of important questions revolves around the size and siting of solar power. Some believe that the proper solution involves large-scale solar arrays in the desert, such as Abengoa’s Mojave Solar Project or the Ivanpah Solar Array. In contrast, others argue that the state should favor a distributed power system, with rooftop arrays and energy storage systems satisfying on-site energy demand.

The Desert Renewable Energy Conservation Plan, which has been in the works for five years, generally embraces large-scale development. The Plan is a 10,000-page draft document that sets out a “landscape-scale renewable energy and conservation” plan for more than 22 million acres of desert in seven California counties. The Plan attempts to balance development of 20,000 megawatts of new renewable energy with conservation goals for desert landscapes and species. The Plan aims to concentrate projects in “Development Focus Areas” with strong renewable resources, access to transmission, and where developers can effectively mitigate environmental impacts.

The Plan’s public comment period closed on February 23, 2015. The four agencies responsible for the Plan (the California Energy Commission, the California Department of Fish & Wildlife, the U.S. Fish & Wildlife Service, and the U.S. Department of the Interior) received over 12,000 comments. Prominent commenters include the U.S. Environmental Protection Agency (EPA) and five of the seven counties in which the Plan would operate.

The counties are concerned that the Plan would have disparate impacts on different counties, excessively burden private land, and could close off private land to other lucrative uses such as agriculture or mining. Particularly, some counties worry about being burdened with costly environmental mitigation projects without necessarily enjoying economic benefits from local projects. Additionally, some counties noted that the Plan’s Preferred Alternative would designate roughly three times as much private land as public land for development, while setting aside roughly 1.7 million acres of private land for conservation projects. Inyo County is only 2% private land, and San Bernardino County is only 25% private land. These counties thus worry that closing private land for conservation or slating it for exclusive use by renewable energy development could harm local economies. As a result, several counties are threatening to withdraw their support for the Plan.

Meanwhile, EPA has called for a fundamental reconsideration of the Plan’s goals and means. Its comments call into question the need for utility-scale solar development, citing “the sharp decline in the cost of rooftop solar-powered electricity and rapid deployment of energy storage.” As distributed solar becomes more widespread, the need for utility-scale solar power diminishes. This line of argument is popular among environmentalists as well. EPA also expressed concerns about particulate emissions (mostly dust) resulting from disturbance of the desert’s surface, about impacts on ephemeral streams, and on the possible designation of the Silurian Valley (a pristine natural area near Death Valley, where the Bureau of Land Management recently rejected a renewable energy project) as a Development Focus Area.  

The agencies responsible for the Desert Renewable Energy Conservation Plan will now have to wade through the more than 12,000 comments on the current draft. Considering that creating the draft took more than five years, it is hard to know when they may issue a final plan. (Their schedule is silent on the issue.)

In the meantime, distributed solar power is continuing a meteoric rise in California. Under the Go Solar California initiative, which is a set of state incentives for solar power, homes and businesses have installed nearly 1,900 MW of solar power. To put that in perspective, the utility-scale Mojave Solar Project has a capacity of 280 MW, while the Ivanpah Solar array (the largest solar thermal plant in the world) has a capacity of 392 MW. This comparison suggests that it is quite possible for distributed solar power to generate enough energy to offset the need for larger, utility-scale projects.

Using distributed solar power to reduce the need for large-scale projects is a good idea. Distributed generation offers a whole suite of benefits that allow utilities—and thus ratepayers—to avoid many types of costs (including transmission costs, distribution costs, and environmental compliance costs, to name a few). But more fundamentally, distributed generation offers a unique opportunity to preserve the natural environment by improving the built environment. As California ponders how (and whether) to reach 50% renewable energy by 2050, it should emphasize distributed solar power.

Ohio PUC Refuses to Gamble Ratepayer Money on Coal Plant Cost Stability

By Amelia Schlusser, Staff Attorney

The Public Utilities Commission of Ohio (PUCO) recently issued an order granting conditional approval for American Electric Power Ohio’s (AEP) electricity rate plan. PUCO declined, however, to approve AEP’s proposal to transfer excess costs or revenues from the utility’s coal-fired power sales onto ratepayers. The PUCO decision may represent a growing regulatory reluctance to subsidize high-risk fossil fuel plants with ratepayer dollars.

AEP’s Proposal

AEP Ohio sought PUCO approval to implement a Power Purchase Agreement (PPA) Rider that would require ratepayers to pay for any revenue shortfalls the utility incurred through its sales of coal-fired power. This rider centered on AEP’s ownership interest in two Ohio coal plants that were constructed in the 1950s. Under AEP’s proposal, the utility would sell power from these coal plants into the PJM Interconnection’s wholesale electricity market. AEP would deduct its operating costs from power sales revenues, then pass the difference onto the utility’s ratepayers. Thus, if the revenues exceeded the utility’s costs, ratepayers would receive a credit on their electricity bills. If the utility’s costs exceeded the revenues, ratepayers would be charged extra to make up the difference.

AEP argued that this PPA rider would “be used as a hedge against future market volatility, in order to stabilize customer rates.” According to the utility, the coal plants’ fixed costs are relatively stable in comparison to wholesale electricity costs. Therefore, when market prices rise (and AEP’s revenues are high), AEP’s ratepayers would receive a credit on their bills. When market prices drop, AEP’s ratepayers would be on the hook for the utility’s revenue shortfalls. The PPA rider would thus serve as a hedge against price volatility in the wholesale market, and in AEP’s view, ratepayers would benefit from more stable electricity rates.

PUCO’s Conclusion

PUCO acknowledged that the proposed rider would reduce ratepayer vulnerability to market volatility to some extent. However, the commission questioned whether AEP’s proposal would actually benefit ratepayers. In answering this question, PUCO noted that AEP’s ratepayers would not actually receive any of the power from the two coal plants. The PPA rider would therefore only provide a financial hedge against price volatility, and ratepayers would not directly benefit from the facilities’ power generation.  

PUCO then assessed whether this financial hedge was likely to benefit or harm ratepayers. The commission noted that the utility’s own projections on the rider’s rate impacts were inconsistent, ranging from an estimated $52 million net cost to an $8.4 million net benefit. The PUCO concluded that while the rider’s potential impacts were highly uncertain, the potential costs to consumers outweighed the potentially negligible benefits. The Commission ultimately found AEP’s arguments unpersuasive and was unable to conclude that the rider would actually promote rate stability or was within the public interest. Citing “considerable uncertainty with respect to pending PJM market reform proposals, environmental regulations, and federal litigation,” PUCO found that it was inappropriate to approve AEP’s rider proposal.

A Transparent Attempt to Pass Risks onto Ratepayers

AEP’s rider proposal appears to be a thinly veiled attempt to hedge itself against potential economic losses associated with its coal-fired generation. Both the 1.1 gigawatt (GW) Kyger Creek coal plant and the 1.3 GW Clifty Creek coal plant will celebrate their 60^th birthdays this year. At the time these plants were constructed, their heat rates were approximately 9,100 BTUs per kilowatt-hour of generation, According to the facilities’ respective websites, these were the two most efficient coal plants in the U.S. in 1955. Under the EPA’s proposed Clean Power Plan, however, Ohio coal plants are expected to improve their heat rates by 4–6%. During AEP’s rate plan proceedings, PUCO staff argued that ratepayer benefits from the proposed rider would be highly dependent on cost stability at these two coal plants, and noted that these costs “could increase significantly over the next few years as a result of additional capital expenditures, increases in coal prices, and environmental regulations.”

A number of environmental and industry interveners raised concerns that AEP’s rider aimed to force ratepayers to subsidize the utility’s aging coal plants and protect AEP’s investors from risks presented by future carbon and environmental regulations. These arguments may have influenced PUCO’s decision to reject the PPA rider. The Commission admonished AEP for attempting to maintain discretion to discontinue the rider after a two-year period, finding it “evident from AEP Ohio's testimony that the Company has made no offer to ensure that customers receive the alleged long-term benefits of the PPA rider.”

According to the U.S. Energy Information Administration, “Ohio is the third largest coal-consuming state in the nation after Texas and Indiana.” The PUCO’s apparent willingness to protect ratepayers from the risk of rising coal costs at the expense of utility profits may thus represent a sea change in the utility regulatory arena. On the other hand, the decision may simply stem from the PUCO’s reluctance to capitulate to overt utility self-dealing at ratepayer expense. In either case, it seems inevitable that these types of schemes will become increasingly common as coal power profits wane, and the PUCO should be commended for rejecting AEP’s rider proposal.

For more information on the PUCO decision, see EnergyWire’s coverage of the topic.