Utilities

A View from the FERC - Part III - Time to Keep the Lights On

March 16, 2015 06:40
by Tricia Caliguire
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.”  

Carbon Dioxide | Carbon Emissions | Climate Change | Regulation | Utilities

Community Solar - A New Path in Illinois

March 5, 2015 11:55
by Tricia Caliguire
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.

Regulation | Solar Energy | Utilities

The Keystone XL Pipeline Veto: Much Ado ...

February 27, 2015 18:39
by J. Wylie Donald
When one talks of pipelines in recent days one hears nearly an incessant buzz about Keystone XL, as if that is where the real action is. But it isn't, notwithstanding the histrionics over President Obama's veto of S.1, the Keystone XL Pipeline Approval Act. The real action lies not with an 850,000 barrel per day oil pipeline, but instead with the natural gas pipelines that are needed to supply the natural gas electricity generating plants that will be required to replace, in part, 103 gigawatts of coal powered generation. What are we talking about? Building Block 2 of EPA's Clean Power Plan posits the replacement of coal-fired generation with cleaner natural gas-fired plants. Natural gas plants are also part of the solution to compliance with the strict Mercury and Air Toxics Standards, which are also driving coal plants off the grid. But to get and keep those natural gas plants on-line, the natural gas needs to get there and to do that it needs a means of transportation, which for natural gas, means pipelines. How many miles of pipelines are needed? EPA concluded: "the power industry in aggregate can support higher gas consumption without the need for any major investments in pipeline infrastructure." But the Nation's reliability watchdog, the North American Reliability Corporation, politely disagrees. In its November 2014 review, Potential Reliability Impacts of EPA's Clean Power Plan, NERC noted EPA's position, but then commented: "there are a few critical areas that likely will need additional capital investments. As an example, current and planned pipeline infrastructures in Arizona and Nevada are inadequate for handling increased natural gas demand due to the CPP. Pipeline capacity in New England is currently constrained, and more pipeline capacity additions will be needed as more baseload coal units retire." And that was not the end of it. NERC concluded that more pipeline capacity was needed independent of Clean Power Plan retirements. Further, as should be obvious, pipeline construction will not occur in an instant. NERC points out that "it takes three to five years to plan, permit, sign contract capacity, finance, and build additional pipeline capacity." In other words, planning and permitting of new pipelines is required now if the EPA's initial 2020 compliance date is to be met. But as we reported in a recent post, States aren't even drafting their implementation plans, much less making determinations about what plants to shut down and where pipelines need to be built.Which suggests that we should ask the miles-of-pipeline-needed question again. We have not seen that number but NERC reports that, based on EPA's own estimates for plant retirements due to the Clean Power Plan and other regulatory requirements (primarily the Mercury and Air Toxics Standard), "the power industry will need to replace a total of 103 GW of retired coal resources by 2020, largely anticipated to be natural-gas-fired NGCC and CTs. We tried to compare 103 gigawatts to Keystone XL's 850,000 barrels of oil per day. We came up with a rather stunning number: the energy needed to replace the to-be-retired coal plants is almost 2000 times more than Keystone XL can deliver.* Which leads us back to the beginning of this post: the real action in pipeline permitting is going to be in natural gas. *A barrel of oil contains about 1700 kW-h of energy. So Keystone XL will deliver 850,000 bbl x 1700 kW-h or 1.445 x 10e9 W-h in one day. 103 GW of coal plants operating for 24 hours yields 2472 x 10e9 W-h.

Carbon Dioxide | Legislation | Regulation | Utilities

The Clean Power Plan: A View from FERC, Part II - Infrastructure

February 26, 2015 12:54
by Tricia Caliguire
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.

Carbon Emissions | Regulation | Utilities

The Clean Power Plan: A View from FERC

February 19, 2015 19:30
by J. Wylie Donald
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.

Carbon Emissions | Regulation | Utilities

Executory Forward SREC Contracts - What Exactly Does This Mean?

March 3, 2014 20:25
by J. Wylie Donald
What happens to the payment for a solar renewable energy credit (SREC) when the payor closes its doors?  Maryland citizens are finding out the hard way.  The promises made to some of them are turning up empty. Here are the details.  Greenspring Energy was a promising solar installation company.  As it describes itself:  "Greenspring Energy offers a unique combination of high-quality solar energy systems and the best energy saving products and services in the marketplace today. Created to help people effectively and permanently reduce their utility bills, Greenspring Energy’s products and services will allow you to: Reduce your utility bills with innovative energy saving products, Produce your own energy with solar systems, Take advantage of federal, state, and local incentives to go solar, Increase the value of your property, Reduce your carbon footprint.”  It was a good business model. Following its founding in 2007, Inc. reports it had revenues of $10.5 million in 2010 and 40 employees the next year. Its website boasts 2011 Inc. 500.  Then something happened.   Jamie Smith Hopkins of the Baltimore Sun reports that Greenspring Energy closed its doors at the end of January this year.  Its employees received rubber checks.  And its customers, promised recurring payments for the SRECs associated with the electricity generated from their solar equipment, were likewise burned.  This is not a particularly unexpected outcome.  Entities regularly enter bankruptcy and their creditors take a beating.  The solar industry is no different.  In fact, one website compiled a list of dozens of “Deceased Solar Companies” through early 2013.   But what is not getting a lot of play (or even any) is the effect of a bankruptcy of the SREC provider.  It is probably safe to say that most SREC transfers are the subject of executory contracts, long-term contracts where the provider agrees to transfer the SRECs accompanying its future electricity generation for some future consideration.  In bankruptcy, such contracts may be assumed, or not, at the discretion of the bankruptcy trustee.  11 U.S.C. § 365.   Except, however, where such contracts are forward contracts.  E.g., Master Solar REC Agreement  (NJ BPU 2014) (“Buyer and Seller each acknowledge that it is a “forward contract merchant” and that all transactions pursuant to this Master Agreement constitute “forward contracts” within the meaning of the United States Bankruptcy Code.”).  In that case, the trustee’s right to reject or assume the executory contract does not exist.  11 U.S.C. § 556.  So there is some complexity here.  And it gets worse.  The SREC does not exist but for the generation of 1 MWh of electricity, even if the SREC is sold separately from that electricity.  It is not difficult to conceive of a situation where the value of the contract for the sale of electricity is going in the opposite direction of the value of the SREC contract.  Suppose the bankruptcy trustee has the right to suspend electricity generation, even if it does not have the right to walk away from the SREC contract.  Does an SREC contract have any value if there is no generation? To our knowledge, SRECs (and RECs as well) have not been tested in the furnace of bankruptcy.  We will be interested in seeing how that turns out. 

Renewable Energy | Solar Energy | Utilities

Report on Carbon Capture and Storage from the House

February 20, 2014 19:37
by J. Wylie Donald
Would an 80% premium steer you away from an energy source that was low-carbon, naturally abundant in the United States, not subject to the vicissitudes of weather, incapable of nuclear meltdown and accompanied by a well-established infrastructure?  Suppose the premium was only 40%? Hearings last week before the House Energy and Commerce Committee’s Subcommittee on Oversight and Investigation explored that topic in connection with the development of carbon capture and storage technology. In prepared remarks Dr. Julio Friedmann, Deputy Assistant Secretary for Clean Coal with the Department of Energy, delivered an update on the status of CCS. Coal fuels approximately 40% of the nation's energy needs.  "Because it is abundant, the clean and efficient use of coal is a key part of President Obama's all-of-the-above energy strategy."  A central component of the President's program is the Clean Coal Research Program, which " is designed to enhance [the nation's] energy security and reduce environmental concerns over the future use of coal by developing a portfolio of cutting-edge clean coal technologies."  To accomplish this the Department of Energy is focusing on research to capture carbon dioxide directly from the fuel stream (pre-combustion), from the stack gas (post-combustion) and from combustion in nearly pure oxygen (oxy-combustion, which yields nearly pure CO2 and water, which are easily separated).  Dr. Friedmann went on to discuss the Regional Carbon Sequestration Partnerships, which are investigating the viability of CCS projects in a variety of circumstances.  "Together, the Partnerships form a network of capability, knowledge, and infrastructure that will help enable geologic storage technology to play a role in the clean energy economy. They represent regions encompassing 97 percent of coal-fired CO2 emissions, 97 percent of industrial CO2 emissions, 96 percent of the total land mass, and essentially all the geologic storage sites that can potentially be available for geologic carbon storage.” Last, Dr. Friedmann addressed the commercialization of CCS.  This has two components:  the operation of CCS facilities, and the utilization of the captured CO2.  The idea behind utilization in activities such as enhanced oil recovery and algae production is to "provide a technology bridge" which can smooth the  " transition to the deployment of the large-scale, stand-alone geologic sequestration operations that will ultimately be needed to achieve the much larger emissions reductions required ..."  As for those operations, Dr. Friedmann acknowledged dozens of projects, including 5 he listed by name, where CCS is being tested in commercial environments. But the real interest of the committee, at least as reported in the trade press, was in cost. As reported  in Power and Power Engineering International,  Dr. Friedman  advised that implementing CCS "looks something like a 70% or 80% increase on the wholesale price of electricity."  Second generation technologies could cut that in half. But half is still a 40% increase. Some might pull the plug on CCS right now.  If it is going to raise the price by 40%, that is simply too much.  To our mind, however, that is antediluvian thinking.  Regulation of carbon dioxide emissions is already happening. Climate change is not taking a wait-and-see approach. Inexorably the earth warms, the oceans rise, the world of yesterday is not the world of tomorrow. CCS has a place at the energy banquet.  Further, before turning off CCS, it is useful to consider the costs of the alternatives.  The Energy Information Administration has calculated the "levelized" cost of various energy sources. "Levelized cost is often cited as a convenient summary measure of the overall competiveness of different generating technologies. It represents the per-kilowatthour cost (in real dollars) of building and operating a generating plant over an assumed financial life and duty cycle."  Two things relevant here come out of the EIA table.  First, among dispatchable power (i.e., power that can respond when it is needed), with or without CCS, the most cost-effective power source is natural gas.  Second, when non-dispatchable power is included, even with CCS, coal is more cost-effective than offshore wind and both photovoltaic and thermal solar.  In other words, if the issue is solely cost, coal loses to natural gas and the effect of CCS does not change the outcome.  If the issues are non-cost values, then coal with CCS comes to the table with green credentials, high power density, dispatchable output, good jobs, national security bona fides, and installed infrastructure, many of which coal's renewable competition cannot match. 

Carbon Dioxide | Regulation | Utilities

Contrary Legal Winds at Cape Wind - Opponents of Offshore Wind Sue Asserting Preemption

February 9, 2014 19:34
by J. Wylie Donald
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)

Wind Energy | Utilities

Wind Project "Take" Permits Extended to 30 Years - Eagles Nonplussed

January 7, 2014 07:52
by J. Wylie Donald
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).

Regulation | Wind Energy | Utilities

The Top 6 at 12: Highlights of the Top Climate Change Legal Stories in the Second Half of 2013

December 31, 2013 21:01
by J. Wylie Donald
2013 has drawn to a close; here is our take on the top six climate change legal stories in the last six months.  1.  Climate Change Assessments - Blockbuster legislation may have been evaded once more but that has not stopped those in the trenches. Assessments of climate change risk are becoming more routine. For example, the September 2013 Record of Decision for the Gowanus Canal Superfund Site required assessment of “periods of high rainfall, including future rainfall increases that may result from climate change” in implementing certain aspects of the cleanup remedy.  Another example was provided by the Department of Housing and Urban Development, which in November required in its second round of community block grants for disaster relief that prospective grantees consider in their Comprehensive Risk Analysis “a broad range of information and best available data, including forward-looking analyses of risks to infrastructure sectors from climate change and other hazards, such as the Northeast United States Regional Climate Trends and Scenarios from the U.S. National Climate Assessment, the Sea Level Rise Tool for Sandy Recovery, or comparable peer-reviewed information."  Even the Nuclear Regulatory Commission looked at climate change with regard to its September draft generic environmental impact statement for the long-term continued storage of spent nuclear fuel.  2.  Low Carbon Fuel Standards - In Rocky Mountain Farmers Union v. Corey the Ninth Circuit reversed several district court rulings limiting under the “dormant Commerce clause” the California Air Resources Board’s Low Carbon Fuel Standard.  Although the Commerce clause of the Constitution, U.S. Const., art. I, § 8, cl. 3. “does not explicitly control the several states,” it "has long been understood to have a ‘negative’ aspect that denies the States the power unjustifiably to discriminate against or burden the interstate flow of articles of commerce.’” Rocky Mountain at 31 (citation omitted). California’s Low Carbon Fuel Standard supported carbon dioxide emission reduction “by reducing the carbon intensity [i.e., the amount of carbon dioxide emitted per unit of energy produced] of transportation fuels that are burned in California.”  It thus potentially burdened producers of ethanol in the Midwest and petroleum producers outside California, but that did not matter.  Specifically, the court held that the LCFS was not facially impermissibly discriminatory in favor of ethanol, was not improperly extraterritorial and did not discriminate against petroleum fuels.  Accordingly, California is still on its path to a reduction in the carbon intensity of its fuels by 10% by 2020, as mandated by the 2006 Global Warming Solutions Act. 3.  The Cost of the Grid - On November 14, the Arizona Corporation Commission ruled that Arizona's net metering program should spread the cost of maintaining a reliable grid among all of Arizona Public Service's customers, including its rooftop solar customers. Up to that point rooftop solar customers were paid for the electricity they provided to the grid at retail rates, without any adjustment for the cost of the grid. The Commission concluded that this resulted in a "cost shift" from customers that were paying for the grid, to rooftop solar customers, who weren't.  APS put on a good case demonstrating that rooftop solar customers were substantially benefitting from the grid by drawing power at night, during cloudy weather and during the periods of daylight when solar power production did not exceed the customer's needs. Many have criticized solar power as unfairly subsidized. In Arizona at least, one of those subsidies is being addressed. 4.  New Carbon Dioxide Emission Standards - Following over 2.5 million comments, EPA rescinded its proposed rule governing carbon dioxide emissions from new coal-fired power plants.  In its place it proposed on September 20 a rule setting CO2 emission standards for new large natural gas power plants (1,000 lbs/MW-hr), new small natural gas power plants (1,100 lbs/MW-hr), and new coal-fired power plants (1,100 lbs/MW-hr).  From our perspective, the most significant facet of this new rule is that it actually will apply to plants that are being built.  The withdrawn proposed rule only applied to new coal plants, which EPA concluded would not be built anyway before 2030.  Equally significant, as pointed out in EPA’s news release  on the proposal, is that “EPA has initiated outreach to a wide variety of stakeholders that will help inform the development of emission guidelines for existing power plants.” 5.  The Fifth Assessment Report of the Intergovernmental Panel on Climate Change – The IPCC’s Working Group I issued The Physical Science Basis, its part of the Fifth Assessment Report.  Working Groups II and III will publish in 2014.  Among other things WG I concluded:  "Unequivocal evidence from in situ observations and ice core records shows that the atmospheric concentrations of important greenhouse gases such as carbon dioxide, methane, and nitrous oxides have increased over the last few centuries."  "The temperature measurements in the oceans show a continuing increase in the heat content of the oceans.  Analyses based on measurements of the Earth's radiative budget suggest a small positive energy imbalance that serves to increase the global heat content of the Earth system.  Observations from satellites and in situ measurements show a trend of significant reductions in the mass balance of most land ice masses and in Arctic sea ice. The ocean's uptake of carbon dioxide is having a significant effect on the chemistry of sea water."  But if one remains skeptical, this consensus view of the world’s leading climate scientists should not cause one alarm, the climate change skeptics have not thrown in the towel.  For example, according to one website, “climate science as proclaimed by the IPCC is a morass where what is scientific knowledge cannot be easily separated from speculation and what is wrong.”  One won't find seafarers plying the Northern Sea Route in the skeptic camp, however.  Russia logged a record year of transits in 2013 (over 200), up from just 4 in 2010.  6.  Climate Change Liability Lawsuits - For the first time since 2005, when Comer v. Nationwide Mutual Insurance was filed, there is no climate change liability lawsuit on the docket anywhere. All have been defeated. Comer was the last to succumb, with its opportunity to file a petition for certiorari expiring on or about August 14.  The IPCC Fifth Assessment establishes climate change is not going away, but we will have to wait to see if anyone is going to attempt to make someone pay for it.

Carbon Dioxide | Climate Change | Regulation | Solar Energy | Utilities | Year in Review

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