Source: http://climatelawyers.com/category/Utilities.aspx?page=2
Timestamp: 2017-11-25 00:03:13
Document Index: 379896485

Matched Legal Cases: ['§ 703', '§ 668', '§ 22', '§ 22', '§ 22', '§ 22']

Last week, FERC held the eastern regional technical conference on “Environmental Regulations and Electric Reliability, Wholesale Electricity Markets, and Energy Infrastructure.” The purpose was for the commissioners to hear the specific issues created by EPA’s Clean Power Plan (CPP) relevant to the states, utilities, generators, consumers and transmission operators covered by ISO-New England, Inc., PJM Interconnection LLC, New York Independent System Operator, the Southeastern Regional Transmission Planning, South Carolina Regional Transmission Planning, Florida Reliability Coordinating Council, and the Northern Maine Independent System Administrator. The overwhelming theme of the morning was that, to effectively comply with the CPP, the states, and state commissions, need more time. Most of the speakers recommended that EPA do away with the interim (2020-2029) compliance goals, complaining that there isn’t time between the likely date of the final rule (mid-summer 2015) and 2020 to plan for retirement of existing resources, and to permit, finance, and construct new natural gas combined cycle plants and the natural gas infrastructure on which these new plants will depend. James Frauen from Seminole Electric Cooperative noted that the draft rule would require Florida to rely “almost completely” on natural gas, all of which must be imported. According to Frauen, the one new gas pipeline currently proposed to be built in Florida is already 91% subscribed. (Not to mention that, in regulated markets, the premature retirement of coal plants means stranded assets which must be paid for by the same ratepayers who must finance the new sources.) Mike Kormos, VP of Operations for PJM, frankly stated, “[PJM] needs time and transparency.” He explained that he couldn’t predict the impact of the CPP on reliability because of the unknowns. “We don’t know what the final rule is,” he continued, “we don’t know what will be in the state implementation plans, and we don’t know how the market will respond.” (Note that PJM modeled regional implementation of the CPP using the draft rules though at least one state complained that such modeling was premature.) Which begs the question: what is the rush? Why not give the states more than one year to propose their SIPs and more than just two years for regional SIPs? Keep in mind that the Regional Greenhouse Gas Initiative (RGGI) – a voluntary agreement – took close to five years to develop. The answer may be found in the collision of politics and policy. That President Obama has made the reversal of climate change, and particularly reduction of greenhouse gas emissions, a cornerstone of his second term should come as no surprise. Between his 2008 statement that “under my plan. . . electricity rates necessarily would skyrocket,” and his 2009 pledge in Copenhagen to reduce emissions “17% below 2005 levels by 2020,” he made his intentions clear. After failing to get climate change legislation through Congress in 2010, he turned to EPA. Despite rumors that the rules had to wait until after the 2012 election, it now seems unlikely that they would have been ready before then. What does seem likely is that the Administration wants to have the rules – and the SIPs – firmly in place before Obama leaves office, in January 2017. Hence, the rush. When the final rule is issued this summer, as EPA continues to promise it will be, the states will have one year to file their SIPs, unless this requirement is stayed pending litigation. After EPA reviews the SIPs, the states will have roughly two to three years to begin implementation. The states will be in the same Catch-22 that they found themselves in with the Affordable Care Act: Cash-strapped states may waste time and resources planning for a law that could be thrown out or substantially altered by the courts, but otherwise, they risk that the law will survive legal challenge and, by not having a SIP in place, will be subject to a less-flexible federal program. Senate Majority Leader Mitch McConnell (R-KY) weighed in on the side of delay, warning states that submission of SIPs could subject them to “federal enforcement and expose [states with SIPs] to lawsuits.” If the states don’t cooperate, McConnell reasons, it will “give the courts time to figure out if [the CPP ] is even legal, and it would give Congress more time to fight back.” Supporters of the CPP responded that states who fail to design their own compliance plans will be at a “huge disadvantage.” Meanwhile, the clock is ticking. As FERC Commissioner Philip Moeller pointed out, “we don’t have a whole lot of time … because summer’s coming.”
This week, the Chicago Tribune reports that the Citizens Utility Board (CUB) and the Environmental Defense Fund (EDF) filed a petition with the Illinois Commerce Commission (ICC) to require Commonwealth Edison Company (ComEd) to offer its customers the opportunity to participate in a three-year "community solar" pilot program. Just to get the players straight: ComEd is a regulated electric utility which services close to four million customers in northern Illinois. The CUB is the statutory representative of Illinois utility customers in all proceedings before the commission and federal agencies regulating the utility industry. (These organizations are more often called consumer or ratepayer advocates). On its website, EDF describes itself as a non-profit environmental advocacy and research organization whose mission is to "preserve the natural systems on which all life depends." The ICC is the state agency directed by statute to balance the interests of consumers and service providers "to ensure the provision of adequate, efficient, reliable, safe and least-cost public utility services." Community solar is also known as "shared renewables," "solar gardens" or, sometimes, "virtual net metering." Essentially, in a community solar program, multiple electric utility customers invest in a solar project and share in the financial proceeds, whether that is from the sale of excess power to the grid and/or renewable energy credits, based on their level of investment. Most, if not all, of the customers will not actually be physically connected to the solar facility. The benefits of community solar include reducing the level of investment required of the host residence or business and providing a means for all electric customers to experience the economic (and intrinsic) benefits of solar, even those who would otherwise be unable to install solar on their own residences or businesses (e.g., rented properties; shaded or otherwise unsuitable roofs). On the other hand, the soft costs of marketing and administering a program to multiple small investors can be significant, reducing those economic benefits. Community solar has also met resistance with regulators; while working in government, I heard concerns about soliciting of consumers, particularly seniors, to "go green" without hosting a solar system. (An Arizona solar company was recently fined for deceptive sales tactics, including targeting of senior citizens and making false claims about potential savings, though not related to a community solar product.) Electricity pricing can be confusing for consumers, even when dealing with their local utilities. Regulators are still sorting through the complaints and litigation resulting from the large numbers of electric and gas customers who switched to third-party suppliers over the past couple years, enticed by low natural gas prices and what they thought were fixed-price contracts, but who then faced bills two and three times higher than "normal" as a result of price hikes during the polar vortex events of 2013-14. The other major challenge for community solar has been to bring the utilities on board. Solar, like any form of distributed generation, will reduce the utilities' revenues. Here is where the Illinois proceeding may pave the way for community solar programs nationwide. In any such proceeding, the utility will be able to argue for recovery of administrative costs and fixed distribution costs, as well as for a return on the company's investment. In a twist on traditional community solar, California utility PG&E will begin later this year to offer its customers a stake in solar energy purchased from facilities within the PG&E service territory. Customers will see the extra costs of the solar energy they consume, plus related program costs, with a credit for standard generation that is avoided, on their monthly bills. And, avoiding a frequent criticism of subsidized clean energy programs, the rate structure ensures that customers who don't participate in the program will not share in the costs.
Because I had a seat inside the meeting room at FERC's Clean Power Plan Overview last Thursday, I got a close-up view of the protesters. Most were older (as opposed to the college-student variety), they carried signs, wore matching red t-shirts and, after the first panel concluded, began to chant, “gas is dirty.” Though none of them explained what they meant, and the speakers so far had not focused on Building Block 2 (shifting dispatch from coal to natural gas combined-cycle generators), most of the rest of the crowd understood that they were protesting the Clean Power Plan (CPP) reliance on natural gas-fired power plants to reduce greenhouse gas emissions. Given that the temperature outside was in the single digits, I wanted to ask the group if they knew how the building was heated sufficient for them to wear only t-shirts, but that would have meant risking my seat, so I demurred. The red shirts would have been pleased to hear, later in the day, that the US Department of Energy (DOE) recently completed a study titled “Natural Gas Infrastructure Implications of Increased Demand from the Electric Power Sector,” which found that compliance with the CPP would not require much additional spending for natural gas pipelines. Commissioner LaFleur “questioned [the study’s] conclusions,” including that increased demand for gas can be satisfied by better or more strategic utilization of existing pipeline capacity. Commissioner Clark was more blunt, pointing out that DOE gives the “false impression” that siting of pipelines will be easier than experience – particularly in the northeast – has proven it to be. As if to prove him prescient, last night, FERC staff held a scoping meeting for the PennEast pipeline project, proposed to traverse six, mainly suburban and rural, counties over a 114-mile route in northeast Pennsylvania and west-central New Jersey. Hundreds turned out at the Ewing, New Jersey hearing (the first in New Jersey); most strongly opposed the pipeline; and many spoke in favor of the “no build” alternative. The director of the New Jersey chapter of the Sierra Club, compared the natural gas companies to the British and Hessian invaders who tried “to take our land” in the 1700s (though some might argue that the land more precisely belonged to the British at that point). “This pipeline turns 50 years of public policy and change on its head,” he continued. Supporters of the pipeline included union members (who need jobs) and the gas companies. Though they spoke of the increased reliability of supply for their customers, some of which are power plants, they did not discuss the significant CPP compliance obligations of Pennsylvania and New Jersey and the role that natural gas-fired generation will likely play in meeting those obligations. Which brings us back to the meeting room at FERC. Toward the end of the afternoon, an Environmental Council of the States (ECOS) representative conceded that not all environmental policies align. Nuclear is carbon free, but it is nuclear. Wind and solar are expensive, intermittent, take up lots of space, and interfere with (even kill) birds and bats. The best wind resources are far from load and transmission lines are unsightly and may traverse protected areas. Natural gas plants are cleaner than coal and oil, but the gas has to be brought to the surface and transported, whether by pipeline or tanker truck or train. And, as the red shirts made clear, some think gas too is dirty. To meet the CPP goals in 2030, some policies will have to give.
February 19, 2015 19:30
It is innocuous enough: Conference on Environmental Regulations; but the plainness of title belies what is going on at the Federal Energy Regulatory Commission today. Today is the first public forum at FERC on EPA's Clean Power Plan. It is playing to overflow crowds. Notwithstanding arriving an hour early, I didn't even get to see the Commission, except remotely. One of the panelists characterized the implications of the Clean Power Plan as the most significant transformation of the bulk power system ever. While some might not agree, none would disagree that EPA's involvement in the electricity grid is unprecedented. This tension was evidenced repeatedly. Reliability and affordability are paramount - where are they referenced in EPA's plan? States and FERC regulate power supply and distribution - how is EPA directing States to prefer one source over another? Citizen suits regularly seek to compel compliance with Clean Air Act requirements - who will be the target when a State plan incorporates voluntary initiatives like fluorescent light bulbs or efficiency planning?So that all have the basics: EPA issued its proposed rule last summer. Comments were due in the fall. A final rule is predicted in early summer. EPA has proposed a broad and flexible plan (EPA's terms) to allow the United States to reduce its carbon dioxide emissions 30% below its 2005 emissions. Each State has been given targets with wide flexibility on how it will get there. EPA has identified four building blocks: improvements in fossil fuel plant efficiency, expansion of renewable energy and nuclear power sources, replacement of coal plants with natural gas, and improvements in system efficiencies. State plans are required by 2016, which can be extended to 2017 and even 2018. Requirements kick in by 2020 with the plans fully implemented by 2030. The Commission is holding fora on the subject over the next 45 days. Besides today's National Overview conference, upcoming regional meetings are scheduled for Denver (2/25), DC (3/11) and St. Louis (3/31).The conference opened with FERC Chairman Cheryl LaFleur explaining the Commission's goals. FERC wants to move beyond rhetoric and ideology. There will be three panels focusing on reliability (which is all we will address in this blog), infrastructure and markets. The goal is to identify concrete facts and suggestions to move things forward. The other commissioners lent their views as well. Commissioner Moeller pointed out that the role of wholesale markets has expanded over the last several decades. In so doing, the grid has provided unprecedented reliable and affordable power to consumers. The Clean Power Plan cannot upset those markets. Commissioner Clark stated that the "rubber meets the road" issue is reliability, and responsibility for that falls squarely on State regulators and FERC. There needs to be a granular and technical analysis to make this happen, which will require the permitting of a lot of infrastructure. The analysis will be two-fold: what does the reliability analysis need to look like (things like voltage support, market impact, SIP integration) and how can FERC leverage its expertise to assist EPA. Commissioner Bay echoed the concerns about challenges and FERC assistance; he also emphasized the importance of addressing infrastructure and market operation. Commissioner Honorable likewise saw the exercise as a job of constructively and thoughtfully solving the problem, and in so doing providing assistance to EPA. Acting EPA Assistant Administrator Janet McCabe spoke for EPA. She acknowledged that reliability is absolutely critical and offered that in the last forty years of Clean Air Act activity, at no time have EPA actions affected reliability. Anticipating a topic raised by other speakers, Ms. McCabe was confident that the EPA proposal could be implemented by 2030, but she seemed to be offering flexibility on the interim deadlines; EPA is listening to the States' and industry's concerns about the short term planning horizons. Another anticipated topic was the reliability safety valve (RSV), although EPA did not call it by that name. Ms. McCabe offered that experience with the Mercury, Air Toxics Standards (MATS) demonstrated that compliance could be melded with reliability. Chairman LaFleur commented that her review of the written comments identified five different RSVs that people were considering: 1) a fixed process identified in the rule, 2) a dynamic process that can take account of changing conditions, 3) a rule that takes into consideration the mutual achievability of all state plans, 4) exceptions for particular plants, 5) exceptions for particular evolving circumstances (i.e., a hotline). There was no consensus on what should be written into the rule. The panelists did not see it exactly like EPA did. Focusing on just these two topics (timeline and RSV) one heard the following:TIMING States are not working on their implementation plans because the proposed rule is too uncertain (Environmental Council of the States - Alexandra Dunn, Edison Electric Institute member companies - Gerard Anderson) The timing to build plants, pipelines, and infrastructure is all five years or more - the interim deadline of 2020 is simply not achievable; a longer "glide path" to 2030 is needed (EEI) A longer timeline is necessary (American Public Power Association - Sue Kelly) The deadlines are not realistic - we are facing a short-term "cliff" (National Rural Electric Cooperative Association - Jay Morrison) There is no short-term cliff; PJM has demonstrated this (Sustainable FERC Project - John Moore)Pushing out the interim deadline and easing the "glide path" would make achieving EPA's goals a lot easier (EEI, Environmental Council of the States) RELIABILITY SAFETY VALVE All the contingencies cannot be seen now so there has to be an RSV "baked into the rule" (National Electricity Reliability Corporation (NERC) - Gerry Cauley)No one has defined what a reliability safety valve is so the ISO/RTO Council did and provided specifics in its written comments. Key is that the process for invoking the RSV needs to be written into the rule (Independent System Operator/Regional Transmission Organizations Council - Craig Glazer) The RSV needs to be dynamic - able to adjust based on changing resources over the 15 year implementation period and beyond (NRECA)The need for the RSV is overstated, but if it is available it needs to be tightly written (Sustainable FERC Project)The RSV needs to be available for entities that have approved operations but then find that things go awry (APPA) The EEI companies have not reached agreement on what the scope of the RSV should be (EEI). Other topics that bear paying attention to included: EPA involvement may interfere with the exclusive jurisdiction of the state utility commissioners (National Association of Regulatory Utility Commissioners (NARUC) - Lisa Edgar) Intermittent sources may compromise reliability (NARUC, NERC)The patchwork of state plans may not work together effectively (NERC) Need better coordination of electricity and gas sectors (APPA)EPA did not consider the value of fuel diversity (NRECA)States will be reluctant to bring their voluntary programs into a federally mandated implementation plan (Environmental Council of the States) As can be seen, there are a lot of topics for discussion. We expect the dialog will be intense over the next several months. On one thing there was unanimity, however; all of the panelists wanted FERC to be more than a potted plant. As Sue Kelly of APPA put it, EPA has swept FERC into the maelstrom, FERC cannot be chopped liver.
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Tags: Clean Power Plan, APPA, NRECA, EEI, reliability safety valve, 2030
Would you care to hazard a guess at how long it takes to bring online an offshore wind farm in the United States? At the moment, it is 12+ years and counting. A recent court filing arguing constitutional questions is certain to slow it down some more. In 2001 Cape Wind Associates, LLC, submitted an application to the United States Army Corps of Engineers for a permit to construct an offshore wind power facility in Nantucket Sound. About 9 years later Cape Wind finally procured the approval to move forward from the Department of the Interior. Cape Wind then got down to work and by November 2012 had signed the first U.S. commercial offshore wind lease and long-term power purchase agreements with National Grid and NSTAR Electric Co. Cape Wnd's Construction and Operations Plan was approved by the Bureau of Ocean Energy Management. According to Cape Wind it is now seeking out its project financing. But a new hurdle has surfaced. At the end of January, various plaintiffs - the Town of Barnstable, businesses, a non-profit environmentalorganization, and individuals - all users within NSTAR's electric service area, sued various Massachusetts governmental entities, as well as NSTAR and Cape Wind (see Complaint attached). Their goal is "a declaration that the Commonwealth of Massachusetts violated both the dormant Commerce Clause and the Supremacy Clause when it used its influence over NSTAR's merger request to bring about NSTAR's entry into an above-market wholesale electricity contract with Cape Wind, a politically favored renewable energy project in Massachusetts, to buy electricity at a particular price." The plaintiffs also seek injunctive relief to invalidate the power purchase agreement between NSTAR and Cape Wind. Plaintiffs' theories are based on the following premise: "Massachusetts regulators used their influence over a merger request by NSTAR ..., to bring about NSTAR's purchase of electricity from Cape Wind ..., an in-state renewable energy project, on particular terms." The legal theories are two-fold. First, the Federal Power Act gives the Federal Energy Regulatory Commission exclusive jurisdiction over wholesale electricity rates, charges and terms. Thus, plaintiffs assert, Massachusetts' acts dictating favorable terms for wholesale electricity sales by Cape Wind to NSTAR are preempted by the Federal Power Act. Second, because Massachusetts' acts in effect favor an in-state electricity provider over out-of-state providers, Massachusetts is unlawfully discriminating in violation of the "dormant" Commerce Clause of the Constitution. These theories recently are exceedingly popular in the energy space. Although the dormant Commerce Clause has not persuaded a federal judge, in 2013 preemption was used successfully to challenge state requirements for gas-fired generation in Maryland (PPL Energy Plus LLC v. Nazarian) and New Jersey (PPL Energyplus v. Hanna). Although both decisions are on appeal, if affirmed, they have significant implications for the viability of state renewable portfolio standards. Notwithstanding that dozens of states have RPSs, the argument will be that RPSs regulate rates, charges and terms by implication, even if the legislative, regulatory and contract drafters assiduously leave rates, charges and terms out of their writings. One commentator, however, points out that "the FERC has never indicated that a state's RPS program that includes a directive to utilities to acquire wholesale renewable energy under long-term contracts to be a violation of the FERC's exclusive jurisdiction under the Federal Power Act." So this may be much ado about nothing; time will tell. In the meantime, Cape Wind continues to be delayed. 20140121 Cape Wind Complaint.pdf (253.06 kb)
Tomorrow bald and golden eagles will sleep less soundly. On January 8 the Fish and Wildlife Service’s new rule revising the regulations for permits for the taking of golden eagles and bald eagles goes into effect. According to the FWS, “This change will facilitate the responsible development of renewable energy and other projects designed to operate for decades, while continuing to protect eagles consistent with our statutory mandates.” Eagles and other migratory birds are a substantial threat to wind projects and not because they will cause turbine blades to fail. Rather, turbine blades (and to a lesser extent, towers, guy wires, transmission lines and other constructions in the air space) can be lethal to birds. This poses a serious problem for wind energy companies as birds are legally protected by the Migratory Bird Treaty Act (16 U.S.C. §§ 703-712) and eagles further protected by the Bald and Golden Eagle Protection Act (16 USC §§ 668-668d). Duke Energy Renewables, Inc. recently ran afoul of these requirements at its 176 turbine Campbell Hill and Top of the World wind projects in Wyoming, where at least 14 golden eagles died between 2009 and 2013. In November Duke accepted a plea agreement in “the first ever criminal enforcement of the Migratory Bird Treaty Act for unpermitted avian takings at wind projects.” It included: • Fines - $400,000 • Restitution - $100,000 to the State of Wyoming• Community Service - $160,000 payment to the National Fish and Wildlife Foundation for eagle preservation projects• Conservation funding - $340,000 to a conservation fund for the purchase of land or conservation easements • Probation – five years• Compliance Plan – implementation of a plan at a cost of $600,000 per year with “specific measures to avoid and minimize golden eagle and other avian wildlife mortalities at company’s four commercial wind projects in Wyoming.”• Permit – required application for a Programmatic Eagle Take Permit. The last is directly tied to tomorrow’s rule. “Take” is defined in the regulations as “pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, destroy, molest, or disturb.” 50 CFR § 22.3. “Programmatic take” is “take that is recurring, is not caused solely by indirect effects, and that occurs over the long term or in a location or locations that cannot be specifically identified.” Id. The regulations at 50 CFR § 22.26 provide for permits to take bald eagles and golden eagles when the taking is associated with, but not the purpose of, an otherwise lawful activity. Programmatic permits authorize take that “is unavoidable even though advanced conservation practices are being implemented.” The new rule commentary notes that permits may authorize “lethal take … such as mortalities caused by collisions with wind turbines, powerline electrocutions, and other potential sources of incidental take.” Under the current rule, a take permit was good for only 5 years, which inserted much uncertainty into wind farm projects. The new rule permits wind energy developers to obtain a take permit that runs for 30 years, 50 CFR § 22.26(i), which “better correspond[s] to the operational timeframe of renewable energy projects.” The risk that a wind project will cause unforeseen harm to eagles during this much longer period is mitigated by a new requirement for 5 year reviews, in which the FWS “will determine if trigger points specified in the permit have been reached that would indicate that additional conservation measures ... should be implemented to potentially reduce eagle mortalities, or if additional mitigation measures are needed.” Id. at § 22.26(h). Additional actions that might be taken as the result of the review could be permit changes, including implementation of additional conservation measures and updating of monitoring requirements. Id. Even suspension or revocation of the permit is possible. Id. That the FWS is serious about protecting eagles is demonstrated by the enforcement action against Duke. But the FWS also recognizes that development is necessary. The 30 year permit period appears to be a reasonable compromise (unless one is an eagle).