Posted on August 25, 2014
On August 12th, the 9th Circuit Court of Appeals issued a decision that arguably explains everything from why the Tea Party exists to why otherwise calm and sane executives suddenly lose all their hair. Perhaps most astounding, the decision is clearly correct. Perhaps the law is an ass.
In 2008, Avenal Power submitted an application to EPA for a PSD permit to construct a new 600 MW natural gas-fired power plant in Avenal, California. Although section 165(c) of the Clean Air Act requires EPA to act on such applications within one year, EPA failed to do so.
Subsequently, and before EPA ever did issue a permit, EPA revised the National Ambient Air Quality Standard for NOx. Avenal Power apparently could demonstrate that emissions from the new plant would comply with the old NAAQS, but could not demonstrate that it would not cause an exceedance of the new NAAQS. After some waffling, EPA took the position that it could grandfather the permit application and review it under the prior NAAQS. Citizen groups appealed and the Court of Appeals held that EPA had no authority to grandfather the application.
To the Court, this was a simple application of Step 1 of Chevron. The Court concluded that sections 165(a)(3) and (4) and 110(j) of the CAA unambiguously require EPA to apply the NAAQS in effect at the time a permit is issued. Thus, EPA has no discretion to grandfather permit applications, even though EPA was required by law to issue a permit decision at a time when more lenient requirements were in effect.
I think that the Court’s decision is clearly right on the law. The statutory language seems unambiguous. But what did the Court have to say to those who feel that the result is inequitable, because Avenal was legally entitled to a decision in one year, and would have obtained its permit if EPA had acted timely? Pretty much, tough luck:
Finally, EPA relies heavily on the argument that the equities weigh in favor of Avenal Power. In short, we agree. Avenal Power filed its application over six years ago, and endeavored to work with EPA for years, even after filing suit, to obtain a final decision. But however regrettable EPA’s treatment of Avenal Power has been, we simply cannot disregard the plain language of the Clean Air Act, or overlook the reason why an applicant must comply with revised and newly stringent standards —that is, “to protect and enhance the quality of the Nation’s air resources so as to promote the public health and welfare and the productive capacity of its population.” Honoring the statute’s plain language and overriding purpose, we must send EPA and Avenal Power back to the drawing board. (Emphasis added.)
In other words, EPA screwed up, and Avenal Power got screwed. Imagine having to explain that to your client.
Posted on July 8, 2014
On October 2, 2013, the United States Fish and Wildlife Service (FWS) proposed to list the Northern Long-Eared (NLE) bat as endangered across its entire range under the Endangered Species Act of 1973 (ESA). The NLE bat is native to a large geographic area and hibernates or often roosts in caves or mines with large openings. Within its range, which encompasses some 39 states and much of Canada, NLE bat populations have declined. While an insignificant portion of this decline has been attributed to human activities, the predominant threat to the NLE bat population is White-nose syndrome (WNS) – a fungal disease that is transmitted in cold temperatures and exhibits a particularly high mortality rate.
Under Section 4(a)(1) of the ESA, FWS must consider five factors in determining whether to list the species as endangered: (1) “the present or threatened destruction, modification, or curtailment of its habitat or range,” (2) “overutilization for commercial, recreational, scientific or educational purposes,” (3) “disease or predation,” (4) “inadequacy of existing regulatory mechanisms,” or (5) “other natural or manmade factors affecting its continued existence.” According to FWS, where “one or more of these factors imperils the survival of a species,” an endangered listing may be necessary.
The proposed listing of the NLE bat carries particularly significant implications for the natural gas and mining industries, whose activities will require permitting that may be more difficult to obtain should the NLE bat ultimately be listed as endangered or threatened, even though such operations are acknowledged to insignificantly impact the NLE bat population. Several other industries are likely to be affected as well, such as construction and agriculture.
In Pennsylvania, the Game Commission and Department of Conservation and Natural Resources are in the process of preparing an application to FWS for an incidental take permit (ITP) and habitat conservation plan (HCP) covering foresting activities over 3.9 million acres of state land that may provide habitat for the NLE bat and the endangered Indiana bat. As described in the early scoping document for the proposed application, the draft HCP includes setback distances from roost trees and protection of hibernacula as potential impact “minimization measures.” Although the draft HCP, if approved as submitted, would not cover coal mining activities on such lands, it is possible that agencies may nonetheless consider such measures in coal mining permitting decisions.
Recently, several US Representatives from the Pennsylvania delegation sent a letter to the FWS challenging the proposed listing of the NLE bat as endangered due to its potential impact to several industries. Instead, the Representatives requested consideration of listing the species as threatened, which would allow for establishment of special ESA “4(d)” rules that exempt activities that minimally affect the species.
The FWS responded on June 30, 2014 by extending the NLE bat final listing determination period by six months and reopening the public comment period for 60 days through August 29, 2014, based on “substantial disagreement regarding the sufficiency and accuracy of the available data,” including NLE bat population trends and the probability of transmission of WNS to unaffected areas. FWS also pledged to minimize or avoid the economic impacts described above by exercising “regulatory flexibility available under the ESA.” However, it remains to be seen whether FWS will take a cooperative approach towards industries that could be impacted by the listing decision. A final determination by FWS is expected no later than April 2, 2015.
Posted on June 30, 2014
On May 19, 2014, EPA issued its long-awaited rule establishing requirements under the Clean Water Act for existing power-generating facilities and manufacturing and industrial facilities that withdraw more than 2 million gallons per day from waters of the United States and use at least 25% of the withdrawal exclusively for cooling purposes. The stated purpose of the Rule is to reduce injury and death to fish and other aquatic life caused by cooling water intake structures at existing power plants and commercial and industrial facilities. The rule covers approximately 1,065 existing facilities of which slightly more than half are power-generating facilities.
The Rule as adopted is 559 pages long. Summarizing a very complex rule of that length is virtually impossible. Those facilities covered by the Rule will need to study the Rule carefully to learn exactly how it affects their facility. At the great risk of over-generalization, there are three broad components to the final Rule which are highlighted in the EPA Press Release of May 19, 2014:
• Existing facilities that withdraw at least 25% of their water from an adjacent water body exclusively for cooling purposes and have a design intake flow of greater than 2 million gallons per day are required to reduce fish impingement. To ensure flexibility, the owner or operator of the facility will be able to choose one of seven options for meeting best technology available requirements for reducing impingement.
• Facilities that withdraw at least 125 million gallons per day are required to conduct studies to help the permitting authority determine what site-specific entrainment mortality controls, if any, will be required. This process will include public input.
• New units at existing facilities that are built to increase the generating capacity of the facility will be required to reduce the intake flow to a level similar to a closed-cycle recirculation system.
Any facility not covered by EPA’s rules governing cooling water intake structures will continue to be subject to Section 316(b) requirements set by the EPA, state or territory NPDES permitting director on a case-by-case, best available judgment basis.
EPA began its Section 316(b) rulemaking pursuant to a 1995 Consent Decree with a number of environmental organizations. Whether environmental organizations, the regulated community or anyone else with standing will appeal this latest rulemaking by EPA is anyone’s guess. Certainly there have been statements made that one or more appeals will be filed. Who thinks that a rulemaking 20 years in the making will end quietly?
Posted on June 26, 2014
The National Environmental Policy Act (NEPA) requires federal agencies to evaluate the environmental effects of their proposed actions. When a proposed action may cause significant environmental impacts, NEPA requires the agency to prepare an environmental impact statement that evaluates alternatives including measures to avoid or mitigate impacts. The agency may not divide a single project into separate bites and find that each in isolation would not have a significant environmental impact. Instead, regulations issued by the Council on Environmental Quality require the agency’s environmental review to encompass connected actions and similar actions.
In Delaware Riverkeeper Network v. FERC, Texas Eastern Pipeline Company sought certificates of public convenience from the Federal Energy Regulatory Commission (FERC) authorizing construction and operation of the Northeast Upgrade Project, one of four projects to improve the Eastern Leg of a natural gas pipeline known as the 300 Line. FERC evaluated the Northeast Upgrade project separately from the others on the ground that each project was designed to provide natural gas to different customers pursuant to different contracts within different time frames. FERC concluded that the potential environmental impacts were not significant and terminated its evaluation by issuing a finding of no significant impact. Environmental organizations petitioned for review of the FERC action on the ground that the four pipeline projects were interrelated and cumulatively would, in their view, clear hundreds of forest acres, fragment habitat and adversely impact wetlands and groundwater in significant ways.
On review, the Court of Appeals for the District of Columbia held that FERC’s segmented environmental review failed to meet NEPA’s requirements. The Court reasoned that all four projects involved the construction of a single, physically interdependent pipeline, were undertaken in a close time frame and were financially interdependent. No customer was a customer of a single pipeline segment and no logical justification existed for the choice of where one project ended and the next began. Accordingly, the Court remanded the case to FERC to review the pipeline project as a whole, including its cumulative impacts.
FERC now faces the daunting task of determining how to implement the Court’s holding in other situations. To be sure, in many cases FERC will be able to readily ascertain whether projects involving a single pipeline are physically, financially and temporally interdependent. But in some areas of the country, transmission pipelines are being installed contemporaneously with natural gas wells, gathering lines physically connecting these wells to the transmission pipelines, and supporting roads, impoundments and other infrastructure. Whether these arguably related projects are sufficiently connected or similar to trigger joint NEPA review may turn on whether they involve different ownership, distinct functions, separate financing and customers and clear physical divisions. Resolving these questions may be no easy task, and even then does not necessarily determine whether a full environmental impact statement must be prepared. When performing an environmental assessment of multiple projects together, FERC may still conclude that the environmental effects are insignificant. With so many steps in the analysis that may be controversial, a new wave of NEPA challenges is likely on the horizon.
One postscript for practitioners before the D.C. Circuit. In a punchy concurring opinion, Judge Silberman expressed his dismay at the submission of a brief “laden with obscure acronyms.” For those of us in the environmental bar for whom use of acronyms has become second nature, beware.
Posted on June 25, 2014
After sifting first through 70 proposals and then six finalists from all over the United States, on May 7, 2014 the Department of Energy announced the selection of three offshore wind demonstration projects to receive up to $47 million each over the next four years to deploy grid-connected systems in federal and state waters by 2017. The projects – located off the coasts of New Jersey, Oregon and Virginia – prevailed over project proposals from Maine, Ohio and Texas.
The Energy Department estimates offshore wind could produce more than the combined generating capacity of all U.S. electric power plants if all of the resources in state and federal waters were developed. More than 70 percent of the nation’s electricity consumption occurs in the 28 coastal states -- where most Americans live. Offshore wind resources are conveniently located near these coastal populations. Wind turbines off coastlines generally use shorter transmission lines to connect to the power grid than many common sources of electricity. Moreover, offshore winds are typically stronger during the day, allowing for a more stable and efficient production of energy when consumer demand is at its peak.
At the present time, the only offshore wind project generating electricity and connected to the grid is off of Castine, Maine; I have been legal counsel for the permitting and other project requirements. UMaine's VolturnUS project is a 65-foot-tall floating offshore wind turbine prototype launched last summer and connected to the transmission system on June 13, 2013, making it the first grid-connected offshore wind turbine in North America. The turbine is 1:8th the geometric scale of a 6-megawatt (MW), 423-foot rotor diameter design. It has been operating extremely well in all kinds of weather and sea conditions for almost a full year. For a photo of the turbine, see a previous ACOEL blog post,
The three projects selected are required to deploy offshore wind installations in U.S. waters, connected to the grid, by 2017:
· Fishermen’s Energy proposes five 5-megawatt direct-drive wind turbines approximately three miles off the coast of Atlantic City, New Jersey. The project would be built in relatively shallow waters, with the foundations installed into the seabed, similar to the proposed Cape Wind (Massachusetts) and Deepwater (Rhode Island) projects.
· Principle Power will install five 6-megawatt direct-drive wind turbines approximately 18 miles off the coast of Coos Bay, Oregon, using a semi-submersible floating foundation to be installed in water more than 1,000 feet deep. More than 60 percent of U.S. offshore wind resources are found in deep waters, including the entirety of the West Coast and much of the East Coast, especially New England.
· Dominion Virginia Power will install two 6-megawatt direct-drive wind turbines 26 miles off the coast of Virginia Beach, using a foundation to be installed in relatively shallow waters into the seabed, like Fishermen’s.
The DOE also announced that the proposals from the University of Maine and from the Lake Erie Energy Development Corporation “offered additional innovative approaches that, with additional engineering and design, will further enhance the properties of American offshore wind technology options. This includes concrete semi-submersible foundations as well as monopile foundations designed to reduce ice loading.” The Department has indicated that these two projects were selected to be alternates, and each will receive $3 million over the next year to, as with the three selected projects, bring their engineering and design work from the current 50% level to 100% completion. You can learn more at the Wind Program’s Offshore Wind Web page.
Posted on June 9, 2014
BP Exploration and Production, Inc. (“BP”) was recently dealt another blow in its fight to reinterpret its multibillion dollar settlement for economic and property losses arising from the 2010 Deepwater Horizon disaster when the Fifth Circuit refused to rehear BP’s appeal of a prior district court ruling on “causation nexus” requirements in the agreement. In December 2013, U.S. District Court Judge Carl Barbier ruled that individuals and businesses do not have to prove that they were directly harmed by the oil spill in order to get paid under the terms of the settlement agreement.
In 2012, nearly two years after the spill, BP reached a settlement with the Plaintiffs’ Steering Committee (which acts on behalf of individual and business plaintiffs in the multi-district litigation proceedings) to resolve hundreds of thousands of private economic, property damage, and medical claims stemming from the Deepwater Horizon explosion and oil spill. BP has disputed many of the economic and property damage claims brought pursuant to the settlement agreement. BP argues that the claims administrator was incorrectly interpreting the meaning of the settlement agreement, particularly with respect to whether or not a claimant must submit evidence that its losses were directly caused by the spill.
Judge Barbier, who is presiding over the multidistrict litigation stemming from the Deepwater Horizon disaster, ruled that the settlement agreement did not contain a causation requirement beyond the revenue and related tests set out in the agreement, opening BP’s checkbook to economic loss claimants who may not be able to trace the cause of their damages back to the 2010 disaster. BP already had revised its original $7.8 billion estimate of its potential costs under the settlement agreement up to about $9.2 billion. Later, as it began challenging economic loss claims, BP proclaimed it could no longer provide a reliable estimate of the ultimate cost of the deal.
BP appealed the district court’s ruling to the Fifth Circuit Court of Appeals, claiming in December that it had to pay hundreds of millions of dollars to businesses and individuals that exaggerated losses from the disaster. The Fifth Circuit affirmed the district court’s ruling in March 2014, and on May 19, declined to rehear BP’s appeal. In a strongly worded dissent joined by two other justices, though, Judge Edith Clement argued that the district court’s rulings would “funnel BP’s cash into the pockets of undeserving non-victims” of the 2010 spill, adding that the appeals court had made itself “party to this fraud” by rejecting BP’s arguments. Judge Clement concluded that “another court surely must resolve this.” BP clearly agrees and has vowed to appeal its case to the U.S. Supreme Court, declaring that “no company would agree to pay for losses that it did not cause, and BP certainly did not when it entered into this settlement.”
Ted Olsen, BP’s lead attorney, said in a 60 Minutes segment in May that the company would take its argument “as far as it is necessary to go to make sure that this settlement agreement is construed properly.” The New Orleans Times-Picayune reports that some experts following the case expect that the Supreme Court will not take up the case, but suspect that BP’s true motive may not be to win on appeal, but to simply prolong the litigation and delay paying claims. The Fifth Circuit lifted its stay on payout of settlement claims, and the Supreme Court just rejected BP’s request that the Supreme Court reimpose the stay pending filing and disposition of its petition for writ of certiorari.
Meanwhile, in the midst of its attempt to walk back from the economic and property loss settlement it negotiated and—at the time—happily agreed to, BP rejected a $147 million claim from the National Oceanic and Atmospheric Administration (“NOAA”) demanding additional funds to conduct its ongoing Natural Resource Damage Assessment (“NRDA”) activities related to the Deepwater Horizon oil spill. NRDA is the process created by the Oil Pollution Act (“OPA”) and its implementing regulations that authorizes natural resources Trustees to assess injuries to natural resources caused by oil spills and spill response activities, and to restore the injured resources. OPA requires that the party or parties responsible for the oil spill pay for the reasonable costs incurred by the Trustees to carry out the NRDA and restoration.
Last July, NOAA submitted a claim to BP for the estimated costs of NRDA activities that NOAA planned to implement in 2014. NOAA’s claim includes $2.2 million for research on the recovery of coastal wetlands, more than $10 million to remedy damage to dolphin and whale habitat, and $22 million for oyster habitat restoration. The Financial Times (free subscription required) reports that BP rejected the majority of NOAA’s requests, saying it was concerned by “the lack of visibility and accountability” in the process, and the unwillingness of the Deepwater Horizon NRDA Trustees (a handful of U.S. federal agencies and five Gulf Coast state governments) “to engage in technical discussions of the substantive issues.” The Financial Times reports that “BP said it had paid for work that was not done or done properly, been double-billed for the same study, and not been allowed to see research findings that it had been told would be shared”—evidence BP argues could be used at the trial over civil penalties to show that ecological damages from the spill are much less than once feared.
According to an April 30 report on BP’s website, BP has already paid nearly $1.5 billion to federal and state government agencies for spill response, NRDA activities, and other claims related to the Deepwater Horizon spill, and over $11 billion to individuals and businesses. I need to disclose, too, that my firm is assisting several claimants to the BP settlement fund.
Posted on May 23, 2014
Recently, Governor Cuomo and the NY State Legislative leaders struck a $140 billion budget deal for FY 2014-2015. Historically, the budget process in New York is messy (sometimes very messy), protracted (with the budget often being late, sometimes very late) and largely plays out behind-the-scenes among the “three men in the room” (Governor Cuomo, Speaker Silver and Senate Co-Leader Dean Skelos). Nevertheless, the FY 2014/2015 budget was passed on time this year and without too much background noise.
How did the environment fare you ask? That might depend on who you ask. Parks advocates were declaring victory and applauding the infusion of $92.5 million in park capital funds, (which the State Senate initially had rejected) for repairs and restoration at New York’s state parks and historic sites. This is the third year of robust capital funding for parks after several years of severe cuts in parks funding, although Park state officials had identified more than $1 billion of required park rehabilitation projects across the state. On the environmental front, notwithstanding some modest successes in the budget process, the environmental community largely believes the new budget falls short when it comes to protecting the environment, making New York more sustainable and preparing New Yorkers for the challenges of climate change. Moreover, many of the so-called advocacy successes were, in reality, merely successful efforts to beat down some pretty bad ideas.
Here are some of the highlights:
1. The Environmental Protection Fund (the “EPF”): The EPF was established in 1993 to fund environmental projects that protect the NYS environment and enhance communities, including in the areas of open space (such as purchasing land for the NYS Forest Preserve), parks, recreation, historic preservation and restoration, habitat restoration, farmland conservation and solid waste management (including upgrading of municipal sewage treatment plants). The EPF, which once stood at $255 million but suffered deep cuts during the recession when it was raided to support the State’s General Fund, was increased in the FY 2014/2015 budget to $162 million, a $9 million increase over last year’s funding level, continuing the progress toward restoring the EPF. The environmental community had sought an increase to $200 million.
2. Brownfields Clean-up Program: No consensus was reached among the Assembly, Senate and Governor during the budget process on the needed reforms to the Brownfield Clean-up Program (“BCP”) and extension of the BCP tax credits deadline. Unless the Legislature and Governor can agree on a bill before the end of the legislative session in mid-June, the program will expire at the end of 2015. Negotiations are continuing on a compromise bill and there are at least 4 competing proposals currently on the table.
3. Reauthorization of the State Superfund Program: The budget agreement did not include new funding for the State’s Superfund program. It is hoped that this issue will be taken up along with a BCP bill and funding.
4. Clean Energy: Proposals from the Assembly and Senate to divert to the General Fund up to $218 million from the New York State Energy Research and Development Authority (“NYSERDA”) budget, which supports clean energy projects, energy-related job creation and greenhouse gas emissions reduction, were defeated.
5. Pesticides: The Governor had proposed to significantly gut the Pesticide Sales and Use Reporting Law. The Senate refused to go along with the Governor’s proposals, whereas the Assembly proposed to modernize the law. No consensus was reached so the law remains in effect.
6. Diesel Emissions Reduction Act (“DERA”): The Governor and Assembly acquiesced to the Senate’s desire to delay the deadline for compliance with New York’s DERA by one year. Accordingly, the State now has until the end of 2015 to bring the State’s fleet into compliance with the Act.
7. Mass Transit/the Metropolitan Transportation Authority: The final budget diverts $30 million in funds dedicated for mass transit to pay State debt, a disappointing loss at a time of record mass transit ridership.
Overall, one might characterize the final budget as being good for the environment mostly because of what it did not accomplish than for what ultimately was included in the FY 2014/2-15 budget.
Posted on May 21, 2014
With a heap of fanfare, in mid-February, New York’s Governor Cuomo announced that the NY Green Bank is open for business. Cuomo began ramping up his clean energy policy last summer, with the appointment of Richard Kauffman, as New York’s chairman of energy and finance, and Chair of the New York State Energy Research and Development Authority (NYSERDA). Kauffman was the former U.S. Energy Secretary Steven Chu’s senior advisor on clean energy finance. NY’s energy and finance chair is making it clear that government subsidies alone have not been successful in creating a robust clean energy marketplace. Kauffman believes that government could encourage the development of private sector capital markets by helping to foster a demand for a low carbon economy. The creation of new Green Banks could lead to permanent, steady and reliable financing for clean energy efficiency projects, and create clean-energy jobs along the way. It’s a win- win for everyone, ensuring a low carbon future and building long-term economic prosperity. New York is not alone, the United Kingdom has a national Green Investment Bank, and in the U.S., Connecticut, Vermont and Hawaii, have Green banks. New York expects that NY Green Bank will advance the state’s clean energy objectives.
Established in June 2011, Connecticut’s Clean Energy Investment Authority was the first state green bank, the first of its kind in the country. On the federal level, the Green Bank Act of 2014 was first introduced in April, in the U.S. House of Representatives by Congressman Chris Van Hollen of Maryland, and Senator Chris Murphy of Connecticut introduced a companion bill in the Senate, as well. In 2009 a bill passed the House, but not the Senate. The Green Bank Act of 2014 would establish a Federal Green Bank with a maximum capitalization of $50 billion from Green Bonds and the authority to co-fund the creation of state-level Green Banks with a low-interest loan of up to $500 million. The legislation provides for the Green Bank to be supported with $10 billion in “Green Bonds” issued by the Treasury; it will have a 20 year charter and will be able to acquire another $40 billion from Green Bonds. Passing the Green Bank Act of 2014 would give all states the option to receive funds from the federal government to assist with financing on a local level and to encourage the movement to a clean energy future. This appears to be yet another arena where the states will take the lead and eventually the federal government will follow.
NY Green Bank is a state sponsored investment funding institution created to attract private funds for the financing of clean energy projects. Mainly, it is a public-private financing institution having the authority to raise capital through various means ― including issuing bonds, selling equity, legislative appropriations, and dedicating utility regulatory funds ― for the purpose of supporting clean energy and energy efficiency projects. NY Green Bank got started with an initial capitalization of $218.5 million, financed with $165.6 million of uncommitted funds raised through clean energy surcharges on the State’s investor owned utility customers, or idle clean energy ratepayer funds, combined with $52.9 million in auction proceeds from emission allowances sales from the Regional Greenhouse Gas Initiative (RGGI). The $218. 5 is meant to be a first step in capitalizing the $1 billion NY Green Bank initiative announced by the governor in his 2013 State of the State address.
NY Green Bank is a division of the NYSERDA, a public benefit corporation aimed at helping New York State meet its energy goals: reducing energy consumption, promoting the use of renewable energy sources, and protecting the environment. Globally, we have seen natural gas and renewables gaining ground at the expense of crude oil and coal.
On April 10, I had the pleasure of hearing Alfred Griffin, the President of the Green Bank, and Greg Hale, Senior Advisor to the Chairman of Energy and Finance Office of the Governor of NY, speak at a roundtable sponsored by Environmental Entrepreneurs (E2). They explained that NY Green Bank was created in December 2013, when a Public Service Commission (PSC) order, provided for its initial capitalization. The order was issued in response to a petition filed by NYSERDA seeking clean energy funds. Griffin and Hale see the $1 billion dollar investment fund as breaking down barriers for projects that are currently neglected. NY Green Bank, however, is not there to provide operating capital, it is there for project capital. They are seeking credit worthy projects and looking to promote standardization. These types of clean energy projects will be a bridge to private markets, eventually not requiring any public subsidy, and ultimately becoming sustainable. NY Green Bank will need impactful deals to demonstrate market success. In the clean tech space, investors are setting investment targets for private equity activity. Residential rooftops are among the type of projects being considered. The bank, for example, would work with a private partner to seed investment in a solar power company for solar panel construction at a specific site. The money would be directed for the panels not salaries or operating expenses. Given the global makeup of energy consumption, energy investors here and abroad are looking to leverage growth opportunities to decide where to invest growing dollars to take advantage of shifts in the energy market. New York state, although, not first, is situated right where it should be.
Posted on May 5, 2014
Last month, after 30 years of negotiations between the parties, an arbitration decision set the price to be paid by the Confederated Salish Kootenai Tribes (CSK) to PPL Montana to acquire the Kerr Dam. The tribes expect the dam -- the first major hydroelectric facility owned by a tribal entity -- will serve as a driver for economic development for tribal members, residents of the Flathead Reservation, and the surrounding area. The dam will operate under the same licensing requirements applicable to PPL Montana and will sell energy generated by the dam on the open market. The dam has the generating capacity of 194 megawatts, standing at 205 feet high and 541 feet long.
After considering arguments by the tribes and PPL Montana, a panel of the American Arbitration Association set $18,289,798 as the price to be paid by the CSK to acquire the dam. This price includes $16.5 million for the existing plant and $1.7 million for required environmental mitigation and was the original price agreed to by the parties in a negotiated deal in 1985. The tribes had argued to the panel that $14.7 million would be a fair price while PPL Montana maintained the tribes should pay close to $50 million for the dam.
The arbitration decision is a culmination of a long history of the construction and operation of the dam. Negotiation for purchase has been going on since 1984 when the 50-year lease terminated. Understanding the debates surrounding the dam requires some explanation. In 1934 a subsidiary of the Montana Power Company began construction on the Kerr Dam on tribal lands on the Flathead River despite opposition from members of the Flathead Indian Reservation. In 1938 the construction was completed and named after the then CEO of Montana Power Co., Frank Kerr. The construction financing for the project included a 50-year term lease that provided for lease payments to the tribes for the dam, which is located on tribal lands and uses tribal resources.
The arbitration decision indicated that the purchase can occur after September 5, 2015. Energy Keepers, a federally chartered corporation owned by the tribes is expected to tender the purchase money early in September 2015. The CSK Tribes hopes to develop the dam as a self-sustaining energy source for the tribes as well as a revenue source. The Tribal Council is expected to choose a new name for the dam after the transfer.
In 2011 the tribes competed for and received a federal grant, which was available for energy projects. The grant money funded a feasibility study to assess energy efficiency improvement projects and to implement energy conservation measures in existing tribal facilities. The grant funding also supported the development of an organizational structure to acquire the dam.
Not all tribal members supported acquisition of the dam. The arbitration process ran from February 3 to March 3, and some tribal members have objected that lack of notice means that public comment should be allowed at this time. Additionally, some tribal members have noted in the media the need for caution in going forward. For example, some have emphasized that, after the purchase, the dam will no longer be a taxable asset and tax support for schools in the area will be lost or will need to be funded from other sources. Preparation for the transition to tribal ownership has begun, and the tribes are working with current employees at the dam who are tribal members and searching for engineers and information technology employees.
Posted on April 30, 2014
Ethanol prices appear to be on the rise. Weather and an increase in exports appear to be responsible for the uptick. The reason for the reported jump in ethanol prices has to do with turbulent winter weather and increasing United States (U.S.) exports, largely to Brazil. Ethanol has wide usage in both countries. The Renewable Fuels Association reported that for 2011, the U.S. and Brazil accounted for 87% of the world’s ethanol fuel production. Some U.S. ethanol plants have stopped production in part because of droughts that have ravaged much of the nation’s crops and pushed commodity prices so high that ethanol has become too expensive to produce.
Bioethanol produced from fermentation of carbohydrates in sweet and starchy crops like sugar cane and corn, has gained in popularity as concerns about energy security and rising oil prices have become more acute. Ethanol fuel, an alcohol derivative, is a renewable motor fuel that is used as a biofuel additive for gasoline. Most cars in the U.S. today run on blends of up to 10% ethanol. Today’s typical fuel pump blend, E10, is 10% ethanol and 90% gasoline. Backed by government subsidies and mandates, ethanol plants rose in the Corn Belt, generating a new market for crops and billions of dollars in revenue for producers of this corn based fuel blend. Generally, oil companies have opposed using higher concentrations of ethanol, and have tried to get Congress to change federal rules so that we use less ethanol.
The U.S. EPA (EPA) has not been immune to the ethanol crunch crisis. Last November, EPA proposed slashing the corn ethanol mandate to 13.01 billion gallons this year, down from 14.4 billion gallon requirement outlined by federal statute. After already proposing to reduce the corn ethanol mandate, this year, on March 27, in a congressional hearing, U.S. EPA Administrator, Gina McCarthy defended the proposal, citing “infrastructure challenges and the inability at this point to achieve the levels of ethanol that are in the law.” The U.S. EPA is the agency charged with the responsibility for developing and implementing regulations to ensure that fuel contains a minimum amount of renewable fuel. Together with many stakeholders, EPA developed the Renewable Fuel Standard (RFS) program, and in 2005, the Energy Policy Act (EPAct) created the first RFS program. The program established the first renewable fuel volume mandate in the United States.
The RFS program sets forth a phase-in for renewable fuel volumes beginning with 9 billion gallons in 2008 and ending at 36 billion gallons in 2022. As required under EPAct, the original RFS program (RFS1) required 7.5 billion gallons of renewable- fuel to be blended into gasoline by 2012. The EPA proposed reduction in the mandate would have significantly affected this year’s corn demand. In October 2013, the Renewable Fuels Association reported that the proposed 1.4 billion gallon reduction in the ethanol mandate would reduce corn demand by 500 million bushels, and result in a reduction in corn prices.
However, with the recent rise in corn prices, there is speculation that U.S. EPA could be reversing course. If U.S. EPA backtracks on its plans there could be more drift in corn prices. Ethanol prices are not merely dependent on what action U.S. EPA choses to undertake. On the federal level, the United States Department of Agriculture (USDA) conducts a large amount of research regarding ethanol production in the United States. Much of this research is targeted toward the effect of ethanol production on domestic food markets. So the oil industry, food companies and livestock sector will all be strong voices to determine what’s up with ethanol prices. As yet, there is no final rule from U.S. EPA.
Posted on April 14, 2014
Last week, in response to shareholder requests that it disclose information regarding how climate change might affect it in the future, ExxonMobil released two reports, one titled Energy and Climate, and one titled Energy and Carbon – Managing the Risks. They actually make fascinating reading and seem to represent a new tack by ExxonMobil in its battle with those seeking aggressive action on climate change.
The reports do not deny the reality of climate change. Indeed, the reports acknowledge climate change, acknowledge the need for both mitigation and adaptation, acknowledge a need to reduce fossil fuel use (at some point), acknowledge the need to set a price on carbon, and acknowledge that ExxonMobil in fact already is making future planning decisions utilizing an internal “proxy” price on carbon that is as high as $80/ton of CO2 in the future.
The reaction of the shareholder activists who pushed for the disclosures? They are not happy. Why not?
Because ExxonMobil has said explicitly that it doesn’t believe that there will be sufficient worldwide pressure – meaning government regulations imposing very high carbon prices – to reduce fossil fuel use sufficiently quickly enough to limit global temperature rise to 2 degrees Celsius. It also does not believe that worldwide carbon regulation will leave it with any “stranded assets.”
I understand the moral case against fossil fuel use. Personally, however, I’d rather rely on a carbon price that provides the appropriate incentives to get the reductions in CO2 emissions that we need to mitigate climate change. On that score, sadly, it’s not obvious to me at this point that ExxonMobil’s analysis of likely outcomes is actually wrong.
My biggest complaint with the reports is the refusal to recognize that markets react dynamically to new regulatory requirements. The history of big regulatory programs is that they pretty much always cost less than the predictions made before the regulations are implemented. The lesson then is that the current projections of energy cost increases resulting from a high cost of carbon are likely to be overestimated.
Time will tell. At least I hope so.
Posted on March 10, 2014
Environmentalists and utility companies don’t always see eye to eye. But when we do find common ground, big changes can happen. Earlier this month, NRDC and the Edison Electric Institute, which represents all the nation’s investor-owned utility companies, serving 220 million Americans, announced an agreement to work together to bring more clean energy and efficiency into the electric grid.
Moving toward a cleaner, more efficient electric grid is less a question of technology than of policy. Outdated utility regulations can pit utility companies and clean energy against each other. Under the traditional regulatory scheme, utilities have to sell increasing amounts of electricity in order to recover their costs. So when customers start putting up solar panels on their roofs, the utility “loses.” Or when customers weatherize their homes and don’t need as much heat to stay warm, the utility “loses.”
This outdated regulatory model is slowing the growth of clean energy and efficiency, and jeopardizing the development of the grid that utilities and customers would all like to have: an enhanced grid that provides clean, reliable, affordable electricity with less carbon and toxic air pollution. In order to speed up the deployment of clean energy and efficiency across the country, and bring our grid into the modern era, utility companies and customers need to be rewarded for doing the right thing.
NRDC and the EEI have come to a path-breaking agreement on key policy changes that will make our electric grid cleaner and more robust. The most significant change is a shift in thinking. Instead of being in the business of selling electricity, a commodity, utilities should be in the business of providing better quality electricity services. This means more efficient electricity, from diverse clean sources like wind and sun, supplied by a robust, modern grid that can take advantage of clean energy, whether it’s generated from someone’s roof or from a power plant. Both utilities and clean energy providers will be winners if this is done right.
Having the support of utilities is a major step forward in pushing for reform. When utilities are rewarded for making our grid better--cleaner and more efficient--instead of merely for selling more electricity, we’ll see improvements much faster. More clean energy, more efficiency, more reliability, more options for consumers. Working together, with a host of diverse partners, NRDC and EEI can help convince state utility commissions to update their regulatory policies and help usher in a new era of clean, reliable, affordable electricity.
Posted on February 13, 2014
A former federal district judge was fond of telling his law clerks that Fifth Circuit Court of Appeals opinions were like the Old Testament. “You can find something there to support about any proposition you want.” The January 31, 2014 release of the State Department’s Final Supplemental Environmental Impact Statement for the Keystone XL Pipeline Project brought Judge Roberts’ words to mind.
The Keystone XL Pipeline Project backers tout the report’s conclusion that because the Canadian tar sands oil will be developed with or without the construction of the pipeline, it will not “significantly exacerbate the effects of carbon pollution” (to use the President’s avowed standards for pipeline permit approval). On the other hand, pipeline opponents point to the fact the report does not specifically address the project’s greenhouse gas emissions. Both are valid points, but the gist of the report appears to be the project has finally cleared its environmental hurdle.
That said, other hurdles remain. While this long-awaited environmental impact statement is an important step in the process, it is just that, a step. Ultimately, the final decision on the pipeline permit will involve something more akin to the common standard for law firm attorney compensation, the so-called “all factors considered” standard. In this instance, that decision will involve economic and national and international political concerns, as well as how the project affects U.S. and international climate policy.
With the issuance of the report, the 90-day interagency consultation period begins. Once EPA, and the Departments of Energy, Defense, Transportation, Justice, Interior, Commerce, and Homeland Security weigh in, the Secretary of State will at some point make to President Obama a permit recommendation. The President, of course, has the final say.
Stay tuned; the project appears to have cleared another hurdle, but the five year and counting race is far from over.
Posted on October 4, 2013
EPA is still working the kinks out of its New Source Performance Standards (NSPS) for the Oil and Natural Gas Sector, i.e., 40 C.F.R. 60 Subpart OOOO, referred to by many as the “Oil and Gas NSPS” and by some as simply “Quad O”. EPA first published the proposed Oil and Gas NSPS on August 23, 2011, in conjunction with proposed revisions to three other air regulations affecting various segments of oil and natural gas operations. The proposal prompted more than 150,000 public comments and kindled a national discussion on emissions at natural gas well sites. The final Oil and Gas NSPS rule was published in August 2012. Although the rule is most famous for establishing the first federal air standards for hydraulically-fractured natural gas wells, the rule also set significant volatile organic compound (VOC) standards for “storage vessels” used by the oil and natural gas industries.
Several stakeholders responded to the August 2012 rulemaking by filing petitions for administrative reconsideration of the Oil and Gas NSPS. On April 12, 2013, EPA published a notice granting reconsideration for a number of issues and proposing revisions to the storage vessel standards, in particular. Evidently, EPA significantly underestimated the number of storage vessels coming online in the field when it developed the August 2012 final rule, which required individual storage tanks with VOC emissions of 6 tons or more per year to achieve at least 95% reduction in VOC emissions. Tanks are commonly used at natural gas well sites, for example, to store condensate, crude oil, and produced water. In light of an updated tank estimate, EPA recognized that additional time would be needed for manufacturers to produce a sufficient number of VOC control devices.
Most recently, on September 23, 2013, EPA published final revisions to the storage vessel requirements in the 2012 Oil and Gas NSPS. Per the revised rule, which was immediately effective, an individual tank may be considered an affected facility if its construction, modification or reconstruction commenced after August 23, 2011; it has potential VOC emissions of 6 tons or more per year; and it contains crude oil, condensate, intermediate hydrocarbon liquids, or produced water. EPA made a number of important adjustments in the revised rule, chief among them an extension of the compliance date to give tank owners and operators more time to purchase and install controls. For the so-called “Group 1” storage vessels (which were constructed, modified or reconstructed between the August 2011 original proposal and the April 2013 proposal), the deadline to control VOC emissions is now April 15, 2015. For “Group 2” storage vessels (i.e., vessels that come online after April 12, 2013), the compliance deadline is April 15, 2014. Notably, pursuant to the revised Oil and Gas NSPS, operators only have until October 15, 2013 to estimate potential VOC emissions of Group 1 storage vessels for purposes of determining whether the rule applies.
Meanwhile, the agency is continuing to evaluate other issues raised in the reconsideration petitions that were submitted in response to the August 2012 rulemaking. EPA has stated in the past that it intends to address the remaining issues by the end of 2014.
Posted on September 26, 2013
“Shoot first, ask questions later” is how Congressman Chris Stewart described EPA’s efforts to link groundwater contamination to hydraulic fracturing. Stewart is the Chair of the Environmental Subcommittee of the House Committee on Science, Space and Technology, chairing the July 24 hearing on “Lessons Learned: EPA’s Investigations of Hydraulic Fracturing.” Specifically at issue was the EPA’s investigation in Pavillion, Wyoming.
In December, 2011, the EPA issued a “draft” report which concluded that hydraulic fracturing in the Pavillion, Wyoming gas field had caused pollution of the deep drinking water aquifer. The draft report was based upon sample results from two EPA monitor wells and was issued without peer review or stakeholder input.
There were serious flaws with EPA’s work. For starters, EPA failed to complete the monitor wells according to its own guidelines. Annular sealants were not properly installed, allowing cement to impact the water quality. A landowner’s complaint that EPA had an anti-freeze leak during drilling operations was not disclosed in the draft report. EPA exposed the wellbores to painted low-carbon steel casing and welding materials, which are known to contain various organic and metal compounds, yet the report inaccurately stated that stainless steel casing had been used. Moreover, several of the constituents which the EPA attributed to hydraulic fracturing fluids (e.g. glycols, 2-butoxyethanol and phenols) are known to be associated with the high pH cement that the EPA used to complete the wells. The bottom line is that the EPA’s own operations introduced the contaminants that it blamed on hydraulic fracturing fluids.
Subsequent testing by the USGS was unable to verify the EPA’s results. The USGS was unable to find some of the compounds that EPA claimed were present, and other constituents were found at significantly lower levels. The USGS was unable to sample one of the two wells due to improper well construction.
The EPA has now walked away from its flawed study, turning the entire investigation over to the State of Wyoming. The EPA has stated that the draft report will not be peer reviewed or finalized, and that the results will not be used in its national hydraulic fracturing study. Nevertheless, the EPA’s handling of Pavillion has cast doubt over the EPA’s national investigation of hydraulic fracturing intended to develop regulatory policy for unconventional reserves, causing Chairman Stewart to conclude, “given EPA’s rush to judgment in Wyoming…we should question whether the Agency’s ongoing study is a genuine, fact-finding, scientific exercise, or a witch-hunt to find a pretext to regulate.”
Posted on September 4, 2013
There has been a flood (no pun of course) of new stories this month about rising sea levels, acidifying oceans, drought-driven wildfires, and extreme weather events in the U.S. and globally. At the same time, with the official release of the eagerly-awaited Fifth Assessment Report of the Intergovernmental Panel on Climate Change due in several weeks, leaks of a draft portion of the Report are coming out in the media, indicating increasing confidence in the underlying science and in a substantial human role in warming, primarily as a result of burning fossil fuels. Additionally, as reported in the N.Y. Times, it appears that the draft projects that sea level could rise by only about 10 inches by 2100 under the “most “optimistic” scenario. But “at the other extreme,” with emissions continuing to swiftly increase, “sea-level rise could be expected to rise at least 21 inches and might increase a bit more than three feet” by the end of this century—which “would endanger many of the world’s great cities — among them New York, London, Shanghai, Venice, Sydney, Australia, Miami, and New Orleans.” Some believe that the FAR will still understate the likely forthcoming climate disruptions.
Coincidentally (or not?), those of you who still subscribe to the National Geographic Magazine would have seen in August a cover story entitled “Rising Seas”, which leads off with questions a panel of ACOEL members will (coincidentally?) in part be addressing at our Annual Meeting in Boston: “As the planet warms, the sea rises. Coastlines flood. What will we protect? What will we abandon? How will we face the danger of rising seas?” . And rising sea levels are especially of relevance to any ACOEL member living in a state on the Atlantic coast, because sea levels have been rising three to four times more rapidly off the Atlantic Coast than the global average, according to a recent study. For those of you living between the coasts, the San Francisco water supply and Yosemite National Park are both threatened by an out-of-control wildfire, while the western United States are experiencing significant drought.
And while forests burn and seas warm, acidify, and rise, one good news story was the recent launching in Maine of the first grid-connected floating wind turbine outside of Europe.
It also is the first concrete-composite floating wind turbine in the world, using advanced material systems with a unique floating hull and tower design. The 65 ft tall turbine prototype is a one-eight-scale version of a 6 MW, 423 ft rotor diameter design. Currently being developed by the University of Maine and beginning preliminary environmental and permitting work, Maine Aqua Ventus I had been selected by the Department of Energy early this year out of 70 competing proposals as one of 7 winners of $4 million in initial funding. The project is now a finalist for an additional $46.6 million in funding. This project is critical, because floating offshore wind energy projects have the potential to generate large quantities of pollutant-free electricity near many of the world’s major population centers (but far enough away, in water depths up to 400’, to not be visible from shore), and thus to help reduce the ongoing and projected economic, health, and environmental damages from climate change. Wind speeds over water also are stronger and more consistent than over land, and have a gross potential generating capacity four times greater than the nation’s present electric capacity.
(Full disclosure: I am legal counsel for the project)
Posted on August 26, 2013
On August 20, 2013, the U.S. Court of Appeals for the 3rd Circuit in Bell et al. v. Cheswick Generating Station, GenOn Power Midwest, L.P. answered a question of first impression: “whether the Clean Air Act preempts state law tort claims brought by private property owners against a source of pollution located within the state?” In this case, Plaintiffs filed claims under state tort law against the GenOn’s Cheswick Generating Station, a 570-megawatt coal-fired electrical generation facility in Springdale, Pennsylvania for allegations of ash and contaminants settling on their residential property (located within a mile of the plant). The Appeals Court held that “(b)ased on the plain language of the Clean Air Act and controlling Supreme Court precedent, we conclude that such source state common law actions are not preempted.”
This decision was based upon the U.S. Supreme Court precedent found in Intl. Paper Co. v. Ouellette. The question presented by Intl. Paper Co. v. Ouellette was “whether the [Clean Water] Act pre-empts a common-law nuisance suit filed in a Vermont court under Vermont law, when the source of the alleged injury is located in New York.” The U.S. Supreme Court held that: (1) Clean Water Act preempted Vermont nuisance law to extent that that law sought to impose liability on New York point source, but (2) Act did not bar aggrieved individuals from bringing nuisance claim pursuant to law of source state.
The Supreme Court of Appeals of West Virginia has previously applied the Intl. Paper Co. v. Ouellette decision to the Clean Air Act in Ashland Oil, Inc. v. Kaufman. In the Ashland Oil case The Supreme Court of Appeals of West Virginia held that Intl. Paper Co. v. Ouellette “requires the application of the statutory or common law of the source state to an interstate pollution dispute when the pollutants in question are regulated by the Clean Air Act. However, the procedural law of West Virginia shall be followed when the issues are being litigated in this State's courts.”
Thus, it appears, at least in the 3rd Circuit, that while interstate common law disputes are preempted by the Clean Air Act, intrastate disputes are not.
Posted on August 19, 2013
For years the nuclear power industry, which could serve as a climate neutral bridge to a more carbon neutral energy policy, has been hampered by the high cost of electricity production and difficulty in securing new licenses and license renewals. A not insignificant contributor to the cost of nuclear power, and one of the arguments raised against relicensing of older nuclear power plants, has been the necessity for the operators of nuclear power plants to store spent nuclear fuel onsite for an indefinite period of time. This was not supposed to be the case. Years ago Congress passed and the President signed into the law the Nuclear Waste Policy Act, which mandated the Department of Energy to develop a permanent repository for spent reactor fuel.
On August 13, a panel of the United States Court of Appeals for the District of Columbia Circuit, in In Re Aiken County issued a rare order, a writ of mandamus, compelling the Nuclear Regulatory Commission to resume the licensing proceeding on the Department of Energy’s application for a permit to construct a permanent repository for nuclear waste at Yucca Mountain in Nevada. That process was to have been completed in June of 2011 under the Nuclear Waste Policy Act, but the DOE, acting on the President’s direct order, tried to withdraw its license application in 2010 and, though the NRC Licensing Board rejected DOE’s efforts, the Chairman of the NRC, also acting at the President’s request, shut the process down anyway.
The case was brought by two states, two counties, three individuals residing near current temporary nuclear waste storage sites, and the association of regulatory commissioners. The Yucca Mountain project has been controversial for years, having been opposed by environmentalists and local politicians in Nevada. DOE’s failure to find a central long-term repository for nuclear waste has forced the nuclear power industry to continue to store spent nuclear fuel in on-site casks or water filled pools, creating what is perceived by critics as enhanced risk of release of radionuclides to the environment. The decision contains a detailed, lengthy and fascinating discussion of the Executive Branch’s authority to exercise prosecutorial discretion and how that discretion is far different than its discretion to ignore clear statutory mandates.
The majority of the panel held that the Executive Branch, including the President (and by extension executive and independent agencies like the NRC), has no authority to disregard congressional mandates based on policy disagreements with the law in question. The panel concluded that the Nuclear Waste Policy Act and Congressional funding of the NRC’s permit review process created a clear mandate to the NRC to make a decision on the permit application pending since 2011. Finding that the NRC is “simply flouting the law, ” and has “no current intention of complying with the law,” the majority opinion by Judge Kavenaugh (joined by Judge Randolph), flatly rejected the defenses offered by the NRC. The court rejected the argument that Congress had appropriated insufficient funds to complete the project, finding that annual congressional appropriations never provide enough money to finish a multi year project, and that over $11 million exists to continue it. The court also rejected the argument that the NRC’s decision to ignore the law was justified because Congress might not provide funding in the future, concluding that allowing an agency to ignore a clear mandate would “gravely upset the balance of powers between the Branches and represent a major unwarranted expansion of the Executive’s power at the expense of Congress.”
The court also rejected the argument that the failure of Congress to provide future appropriations for the Yucca project demonstrates congressional intent to shut down the process. The Court opined that the measure of congressional intent is in the laws it passes, not what it debates, and that repeal by implication is inappropriate where previously appropriated funds are not taken back and remain available to advance the project. The court accordingly concluded that there is “no justification” for ignoring the clear statutory mandate. Finally, the court rejected the suggestion that an agency’s policy dispute with Congress’s decision is “not a lawful ground” for the NRC or the President to decline to follow the law.
In a dissent, Chief Judge Garland argued that all the NRC did was suspend the proceeding because there were not “sufficient funds to finish the licensing process and that the court should defer to the agency on this judgment, and therefore mandamus should be denied. The majority rejected this, noting that the NRC’s continued repeated and unjustified disregard for the law despite the repeated warnings given by the court rendered mandamus appropriate.
The D.C. Circuit mandamus order will in all likelihood be appealed, and it is certain that the Yucca Mountain project will remain the subject of intense controversy. The stakes for the nuclear energy industry in having the spent fuel storage problem resolved are large. Stay tuned.
Posted on August 16, 2013
Ever since the shock of the oil embargo in 1973 we have been a nation in search of a comprehensive, sound energy policy. It was only a year later, in response to the proposal by Aristotle Onassis to locate an oil refinery on the coast of New Hampshire, that the New Hampshire Legislature adopted the first version of the State’s energy facility siting law.
Today, New Hampshire’s siting law, representing a balance of the need to develop new energy facilities with appropriate protection of the environment, preempts local authority and requires each project to undergo a rigorous comprehensive, consolidated evaluation before a panel of high-ranking State officials from the several different departments having jurisdiction over all the relevant permits. To obtain all State permits and a Certificate from the siting committee, the applicant must be prepared to present the project in a consolidated process, subject to formal discovery, at an adjudicative hearing before the committee. Interested parties and municipalities may intervene and the Attorney General appoints Public Counsel for the case to represent the broad public interest. To take positions in the broad public interest, Public Counsel is charged with the responsibility to represent the interests of the public as a whole, and not simply the narrower positions adopted by intervening parties. To discharge this responsibility, which derives directly from that of the Attorney General in all other cases, the Public Counsel must take positions that balance the public interest in developing new, diversified energy facilities and the need to take into account environmental regulation.
This highly structured, energy facility permitting process is significant regionally and nationally because its standards tend to drive the design of interstate facilities. Current energy policy and its direction may be discerned from trends reflected in the written decisions of the siting committee over time. Other states may be developing approaches to these issues.
Beginning in the late 1990s, a steady stream of energy projects have been presented to the committee. Until the mid-2000s, the majority of those projects involved fossil fuel generation, and in particular natural gas generating stations and transmission lines. As public policy, driven by concerns for global warming, has put increasing emphasis on renewable energy sources, there has been a significant increase in proposals to construct wind energy facilities. What is most striking from this perspective is that no energy project was rejected until 2013, although some facilities were subject to hundreds of conditions in their certificate.
This year, a proposed 30 megawatt wind farm in Antrim was rejected on its “aesthetics”, an indisputably highly subjective standard in search of criteria that will avoid arbitrary and capricious adjudications. Three previous wind power projects have all been approved with essentially the same characteristics, but for the first time the committee, at the urging of public counsel, has declined to approve the project rather than setting forth criteria and conditions that would bring essential predictability to this important technological advance in energy production.
The region and the nation will be well served by a steady expansion in the number of renewable energy projects, and this opportunity has the attention of large, even international, experienced and capable developers. Does the rejection of the Antrim project, despite public support, on the basis of the objections of special interests actively supported by public counsel risk a slowing down or abandonment by developers to the detriment of the region’s public interest in a diversified energy portfolio? Is it coincidence that a wind energy project was rejected recently in Maine, also on highly subjective grounds of aesthetics, a case that was referenced in the New Hampshire proceedings? And shouldn’t we ask whether advancing wind turbine technology is something we find in most places attractive, when it represents a great benefit to the environment and the public interest?
These cases bear watching. The New Hampshire case appears to be headed to the State Supreme Court. Will it turn out that these developments represent a turning away from favorable conditions promoting wind energy, so that wind energy development will decline in the years ahead? For environmentally sound economic development in this region and elsewhere we should hope not.
Posted on June 7, 2013
On the night of his re-election, President Obama told the nation that he wanted “our children to live in an America…that isn’t threatened by the destructive power of a warming planet.”
In the past year, we’ve seen extreme weather, fueled by carbon pollution, cost hundreds of American lives and nearly $100 billion in damage across the country. Yet right now we have no national standards to control carbon pollution from the biggest emitters—the 1500 existing power plants which are responsible for 40 percent of U.S. carbon pollution. NRDC has developed a plan for how the President could use his existing authority under the Clean Air Act to cut this climate-changing pollution from power plants, quickly and cost-effectively.
In a 2011 Supreme Court decision, American Electric Power v. Connecticut, the court ruled that it is the EPA’s responsibility to curb carbon pollution from power plants, new and existing. Carbon pollution limits for new power plants have been proposed and the EPA needs to make them final. But the step that will make the biggest difference is cutting pollution from existing power plants. Under section 111(d) of the Clean Air Act, the EPA could set state-specific standards for average emissions from existing power plants based on each state’s current energy mix. Then states and power plant owners would have broad flexibility in deciding how to meet those standards, using a range of cost-effective measures and technologies.
Not all states line up at the same starting point when it comes to carbon emissions—some are heavily coal dependent, while others rely more on lower-carbon fuels and clean, renewable energy. Developing state-specific standards will give heavily coal-reliant states more realistic targets, while still moving them toward a cleaner energy supply. In addition, states and power plant owners can keep costs down by using a variety of measures to achieve compliance, whether it’s installing a new boiler in an old coal-fired plant, or investing in a home-weatherization program to reduce energy demand. These efficiency measures will help keep energy bills low and also create thousands of jobs that can’t be outsourced.
All in all, NRDC’s flexible, cost-effective proposal can achieve a 26 percent reduction (from 2005 levels) in carbon pollution from power plants by 2020, according to modeling done by the same firm the EPA uses for much of its air pollution modeling. The cost of compliance, about $4 billion, is comparatively low, and is vastly outweighed by the benefits--$25 to $60 billion in savings. These benefits come in the form of 3,600 lives saved, and thousands of asthma attacks and other illness prevented each year due to less air pollution, as well as the value of reducing carbon pollution by 560 million tons. This is twice the reduction that will be achieved by clean car standards.
The President has been very clear about the need to do something to curb global warming. This cost-effective proposal could be his biggest opportunity to take decisive action. He can dramatically reduce carbon pollution from power plants--while creating major health benefits and jobs--using his existing authority under the Clean Air Act.
Posted on May 30, 2013
On Friday, May 17, the Department of Energy (DOE) announced it had conditionally authorized Freeport LNG Expansion, L.P. and FLNG Liquefaction, LLC (collectively Freeport) to export domestically produced liquefied natural gas (LNG) to countries that do not have a Free Trade Agreement (FTA) with the United States from the Freeport LNG Terminal on Quintana Island, Texas. This marks only the second time that the DOE has granted a natural gas export license to non-FTA countries, and only the first after DOE ceased action on all applications pending a study of the economic impacts of LNG exports. The Freeport approval marks a noticeable, but likely incremental shift in US policy towards increased export of natural gas to non-FTA nations, opening up new markets for the boom in domestic natural gas production.
The DOE rejected opponents’ arguments that the project would be inconsistent with the public interest. Among other reasons, the DOE found that the proposed exports are likely to yield net economic benefits to the US, would enhance energy security for the US and its allies, and were unlikely to affect adversely domestic gas availability, prices or volatility. Accordingly, DOE conditionally granted Freeport’s Application, subject to satisfactory completion of an environmental review pursuant to the National Environmental Policy Act (NEPA) by the Federal Energy Regulatory Commission (FERC) and DOE. FERC will serve as the lead NEPA review agency. DOE will subsequently reconsider the conditional order in light of the NEPA analysis led by FERC and include the results in any final opinion and order.
Environmental issues will now take center stage as interested stakeholders seek to influence the government’s conclusions in the NEPA review. In support of its application, Freeport extolled the following environmental benefits of the project:
• Natural gas, the cleanest burning fossil fuel, would replace coal-fired power resulting in substantial reductions in greenhouse gas and traditional air pollutants.
• Compared to the average coal-fired plant, natural gas fired plants emit half as much carbon dioxide (CO2), less than a third of the nitrogen oxides, and one percent of the sulfur oxides.
• Natural gas, if used as a transportation fuel, also produces approximately 25 to 30 percent less CO2 than gasoline or diesel when used in vehicles, and is not a significant contributor to acid rain or smog formation.
Opponents of the project, however, are less convinced of its environmental benefits. These include the Sierra Club, the Delaware Riverkeeper Network (consisting of 80 organizations), NRDC, among others. Specifically, they assert that LNG exports will increase demand for natural gas, thereby increasing negative environmental and economic consequences associated with fracking, the process used for shale gas production. They argue that the DOE’s two-part study of the economic impacts of LNG exports, upon which DOE relied in conditionally granting Freeport’s application, failed to consider the cost of the environmental externalities that would follow such exports, which include:
• Environmental costs associated with producing more shale gas to support LNG exports;
• Opportunity costs associated with the construction of natural gas production, transport, and export facilities, as opposed to investing in renewable or sustainable energy infrastructure;
• Costs and implications associated with eminent domain necessary to build new pipelines to transport natural gas; and
• Potential for switching from natural gas-fired electric generation to coal-fired generation, if higher domestic prices cause domestic electric generation to favor coal-fired generation at the margins.
Sierra Club and other organizations have previously challenged the adequacy of FERC’s and DOE’s NEPA determinations in other LNG export applications. In the first LNG export license approval for Sabine Pass Liquefaction, LLC (DOE Docket. No. 10-111-LNG), Sierra Club, as an intervener in the FERC proceeding, challenged the adequacy of FERC’s NEPA compliance, and the lawfulness of the FERC’s determination to authorize the Project facilities. The FERC addressed these concerns and found that if a series of 55 enumerated conditions were met, the Project would not constitute a major Federal action significantly affecting the quality of the human environment.
After FERC authorized the Liquefaction project, Sierra Club filed a motion to intervene out of time before DOE , again challenging FERC’s NEPA determinations. DOE rejected Sierra Club’s motion, and granted the final order approving the LNG export on August 7, 2012. Sierra Club subsequently sought a rehearing on the final order which was also rejected by the DOE in a January 25, 2013 order.
Similarly, earlier this month, Sierra Club and other environmental organizations objected to the proposed Dominion Cove Point LNG export terminal in Maryland, arguing the project would harm the Chesapeake Bay’s economy and ecology, increase air pollution, and hasten fracking and drilling in neighboring states. On May 3, 2013, the coalition filed public comments and a timely motion to intervene in the proceedings calling on FERC to conduct a thorough environmental review, or prepare an EIS, of the project. The proposed terminal will be the only LNG export facility in the east coast, providing foreign markets with access to natural gas from the Marcellus Shale.
Posted on May 14, 2013
Cheap gas prices driven by a boom in new shale gas development, coupled with more stringent emissions controls for coal fired plants, are causing a shift from coal to natural gas as the primary source of electric power in the United States. In the short term, most welcome this shift because natural gas produces significantly fewer greenhouse gas (“GHG”) emissions. But it appears increasingly certain that in the long run, this shift will result in decreased energy grid reliability and significantly higher electricity costs due to natural gas price volatility.
A recent Duke University study concludes that the cost of compliance with new emissions standards could make almost two-thirds of existing coal fired plants “as expensive as natural gas even if natural gas prices rise.” This combination of low gas prices and the high cost of coal emissions compliance already has resulted in replacement of many coal plants instead of retro-fitting them with expensive environmental controls. Add to that the uncertainty of potential future GHG emissions standards, and construction of new coal fired power plants is at a near standstill.
The Rocky Mountain Coal Mining Institute (“RMCMI”) estimates that these factors will combine to force closure of up to 100 gigawatts of coal plant capacity, or approximately one third of the coal-fired fleet, resulting in a net increase of 32 gigawatts of gas capacity in the next three years. By 2020, RMCMI estimates that gas generating capacity will exceed that of coal, nuclear, and hydroelectric combined. The RMCMI further projects that the shift to natural gas generation will cause the demand for natural gas to exceed even the most rosy new shale gas production predictions, causing volatile natural gas price swings.
Grid reliability problems and gas price volatility were highlighted by Gordon van Welie, the head of New England’s power grid, during recent testimony before Congress. He observed that more than half of New England's electricity is generated from natural gas, which has displaced a more diversified mix of oil, coal, gas and nuclear power over the past ten years.
He testified that even though natural gas generally is plentiful, New England’s inadequate gas pipeline capacity limits supplies during peak usage. For example, during a recent extreme cold snap in New England, “natural gas prices in late January spiked to $34/MMBtu, in contrast to prices below $4/MMBtu across most of the country.” The high gas prices caused wholesale electricity price spikes of more than 100% in January and 300% in February 2013 compared with 2012. There also were “multiple instances where generators could not get fuel to run,” including one instance when more than 6,000 MW were offline due to fuel shortages. Testimony at 7. To avoid even worse problems in the future, he urges increased construction of pipeline infrastructure, but construction of gas pipelines will take time. In the short and intermediate term, he predicts continued price volatility and grid reliability problems during peak usage.
In addition to pressures from increased usage of natural gas in the United States, there also is increasing support within the Obama Administration to side with those seeking to export liquefied natural gas because prices in foreign markets are much higher. If the export of natural gas becomes a reality, then domestic gas prices likely will increase even more.
Although the vast shale gas reserves are fueling a shift to natural gas power generation with a corresponding reduction in GHGs, over-reliance on natural gas will almost certainly have the unintended consequence of causing grid reliability problems and volatile price spikes. This likelihood argues for a more balanced energy portfolio with a broad mix of power from renewable, hydropower, coal, oil, nuclear, and natural gas. To insure future stable energy prices and reliable energy production, electric utilities and state and federal regulators should take a long term view when deciding whether to shift to natural gas generation and decommission existing coal and nuclear plants.
Posted on May 10, 2013
Proposals to export liquefied natural gas (“LNG”) produced in large part from shale gas recovered by hydraulic fracturing techniques or “fracing” continue the public debate about the desirability of exports of other energy resources. This political, regulatory, environmental and trade debate engages powerful politicians, lobbyists, environmental groups, trade associations, developers, producers, state regulatory authorities, consultants, academics, and landowners, and a broad spectrum of the press and public.
On its face, the notion of substantial exports of LNG to both countries with which the U.S. has free trade agreements (FTA) in place and those it does not, seems highly attractive. Such exports would improve the balance of trade deficits, create new jobs associated with the production; and produce tax revenue. And, from the broad environmental perspective, LNG exports would lower greenhouse gas emissions (GHG) in countries with heavy reliance now and in the future on coal or oil for electric generation, or in countries with need for replacement of nuclear facilities.
Query then, what are the factors that engender the impassioned debate on energy resource export policy? Key are: (1) fears of massive development of “frac” gas, freighted with concern over impacts on water, air, and use. Analogous to the Keystone XL battle, another concern is development of the unconventional gas for the benefit of foreign interests, particularly those without an FTA in place with the U.S. (export to those countries with FTA agreements with the U.S. is deemed by law to be in the public interest). (2) A second issue in contention on LNG is the impact on domestic energy prices if significant LNG exports limit availability of natural gas for domestic industrial and other uses. (This issue harkens back to the energy crises of the 1970s when natural gas availability was tight and energy prices sky high.)
So, although not explicitly an environmental-based objection, such opponents of LNG exports find friendly bedfellows with the environmental objectors and the commercial interests concerned about their ability to rely upon and benefit from increased gas supply. Industrial interests argue that stopping exports to non-FTA countries, particularly the insatiable Asian markets, will result in an industrial renaissance with jobs and development growing significantly. And, some opponents of LNG exports to non-FTA countries ironically, (to this blogger at least) express little regard for overall environmental benefit to potential importing countries and thus the globe. Rather, the impact on the United States from development of unconventionally sourced gas supply has been their focus point. Yet, LNG is only part of the energy export debate.
Further complicating this analysis is the parallel potential increase in the export of U.S. coal to energy hungry nations, particularly in Asia. As noted above, there is a broader questioning on the entire topic of U.S. energy resources exports: LNG, oil or refined products and coal. In addition to the Keystone XL pipeline standoff, many environmentally oriented players (e.g., the Sierra Club) and political leaders have expressed reservations about the export of U.S. coal for two primary reasons – the impact on the U.S. of new infrastructure for storage, transportation and increased mining activities, and the increase in GHG emissions worldwide as a result of heavier coal-fired electric generation. And in the past months, several proposed coal export projects have been scrapped. This energy export issue makes for a complicated stew of federal, local and regional politics. What makes the entire public war of words (and the behind the scenes maneuvering) so fascinating is the question of who or what decides where and with what restrictions U.S. energy resources are to be marketed to the world – the federal agencies, the state and local governmental entities, or the market? The next few months may provide guidance on LNG and perhaps the Keystone XL pipeline, however, the national and international implications of these decisions are so important that it is unlikely that peace will settle on these matters for decades.
Posted on April 18, 2013
You may know that Washington State Governor Jay Inslee is a climate champion, first as a long-serving member of Congress and now as Governor. But you may not know that he just finished leading a bipartisan effort that succeeded in passing climate change legislation.
His climate action bill passed the State House March 25th on a bipartisan 61 to 32 vote. The bill earlier passed the Republican-controlled State Senate on a 37 to 12 vote. And a few days ago it headed to Governor Inslee’s desk for a well-earned signature.
The bill commissions an independent evaluation of climate pollution reduction programs in other states and Canadian provinces, and of opportunities for new job-producing investments in Washington relating to cleaner energy and greater energy efficiency. Then it requires the Governor and legislative leaders to use that survey data to plot out together what set of policies will get the State to hit its climate pollution limits established by earlier legislation, including a greenhouse gas emission reduction to 1990 levels by the year 2020.
“The Governor’s climate action bill keeps our state in the game – requiring leaders to map out a strategy to grow our clean energy economy and reduce climate pollution,” said Joan Crooks, executive director of Washington Environmental Council.
And here — in sharp contrast to the other Washington — Republicans and conservative Democrats agreed.
Posted on April 3, 2013
Two items hit my inbox on the same day:
(1) The U.S. is predicted to become the world's largest oil producer and North America to become a net petroleum-exporting region according to the International Energy Agency, and
(2) The Obama Administration is renewing its commitment to wean U.S. cars off of petroleum.
Some might argue that it makes sense to wean cars off petroleum even if we have a lot of it because of the threat of global climate change, but instead the stated justification was “to create jobs and help lower energy costs for middle class families.”
Then came the news that the operating unit of China's largest solar panel company, Suntech Power, recently filed for bankruptcy. Meanwhile, the Obama Administration proposes the creation of a $2 billion Energy Security Trust, funded by revenues from offshore oil leases matching those provided by the Chinese, to subsidize investments in this supposedly vital emerging field.
The disparity between such news and the government actions being taken started me questioning whether it is possible for governments to manage a field as dynamic and ever changing as future energy supplies. "Regulatory lag" has long been a familiar concept in utility rate regulation: by the time regulators get around to approving new rates, the situation has changed. And human beings are justly famous for "winning the last war": by the time that we understand something well enough to develop a broadly-shared consensus, the situation has changed.
This is nothing personal against the Obama Administration or support for renewable energy. I have been teaching a course at the Yale Law School this semester on the history of energy policy in the U.S. since World War II. A theme that runs throughout the course is how policies designed to manage energy supply, regardless of political outlook, lag as much as a decade or two behind the times. For example, Nixon's 1971 oil price freeze lasted until 1981; Eisenhower's 1959 oil import quotas lasted until 1973. In both instances, government policy did a lot of unnecessary harm because the energy supply situation changed much faster than government policies do.
I often wonder why environmental law and energy law are so different. One difference is that environmental problems tend to stand still (or get worse) long enough for us to mobilize the slow processes of government to solve them. We studied and debated acid rain for over a decade before the 1990 amendments to the Clean Air Act, which mandated a 50% reduction in sulfur dioxide emissions over the following decade. Energy markets change within months as new sources of supply and technologies come on line. It makes one wonder whether government policy will inevitably be a day late and a dollar short when it tries to manage future energy sources.