Posted on June 30, 2015
In Jonathan Cannon’s excellent post on Monday’s Supreme Court decision in Michigan v. EPA, he noted that the majority and the minority aren’t actually that far apart in their views on whether EPA must consider costs in this rulemaking. I have a slightly different take: They may not be that far apart, but they’re both wrong.
In fact, the issue in Michigan v. EPA seems so simple that the MATS rule could have been affirmed in a two-page opinion. Judge Scalia notes that the word “appropriate” – on which the entire 44 pages of the majority, concurring, and dissenting opinions focus – is “capacious”. I agree. If so, and if Chevron means anything, “appropriate” is surely capacious enough to allow for an interpretation that does not include cost considerations. That should have been the end of the case.
I do feel compelled to note, however, that Justice Kagan’s dissent also got it wrong, in at least three ways:
- I think she’s flat wrong to suggest that, because the MATS “floor” is based on the top 12% of facilities already in operation, that means that establishment of the floor already takes cost into account. As Justice Scalia cogently notes, those existing facilities may well have been under their own regulatory duress – a duress that may not have considered cost.
- Justice Kagan confuses cost-benefit analysis and cost-effectiveness analysis. For any given goal sought by EPA, the various options provided by the MATS rule may allow power generators to attain the goal in the most cost-effective means possible, but if even the most cost-effective approach were to yield $10B in costs and $10M in benefits, that would fail the cost-benefit test for most people.
- Finally, and most importantly, Justice Kagan got the consequences wrong. Instead of suggesting, as she did, that the majority decision,
"deprives the American public of the pollution control measures that the responsible Agency, acting well within its delegated authority, found would save many, many lives,"
she should have made the point that the majority decision will have no impact on EPA or the MATS rule. The Supreme Court did not vacate the rule; it merely remanded the rule to the Court of Appeals. Justice Kagan’s position should have been that EPA still has sufficient discretion, even on the existing record, to defend the MATS rule within the confines of the majority opinion. Instead, Justice Kagan gave ammunition to those who oppose the rule, by suggesting that it cannot be saved.
A pox on both their houses.
Posted on June 23, 2015
On June 4, 2015, the U.S. Environmental Protection Agency released a draft “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources,” which finds no evidence that hydraulic fracturing activities have led to widespread, systemic impacts on drinking water supplies. According to the draft assessment, between 2000 and 2013, there were an estimated 9.4 million people living within one mile of a well that was hydraulically fractured. The draft assessment supports the assertion that state agencies, as the primary regulator of oil and gas development in the United States, are effectively governing hydraulic fracturing activities by the industry.
Initially announced by USEPA in March 2010, the study has a broad scope. USEPA reviewed each stage of the “hydraulic fracturing water cycle” – including water acquisition, chemical mixing, well injection, flowback and produced water recapture, and wastewater treatment and disposal – to assess for any widespread, systemic impacts on the quality or quantity of drinking water resources. The agency also used an expanded definition of drinking water resources that includes currently undrinkable saline aquifers that might be desalinated for consumptive use in the future.
Although the draft assessment acknowledged that hydraulic fracturing could potentially contaminate drinking water resources, USEPA found that the actual occurrences of such impacts were “small compared to the number of hydraulically fractured wells.” The risks related to hydraulic fracturing activities identified in the draft assessment included: water withdrawal in times of low availability; spills of fracturing fluids and produced water; fracturing directly into underground drinking water resources; below ground migration of liquids and gases; and inadequate treatment and discharge of wastewater.
The draft assessment noted that the primary means of disposing of wastewater from hydraulic fracturing activities conducted in the United States is underground injection wells. However, one notable exception to this finding is in the Marcellus shale play, where USEPA found that most wastewater is reused by industry. The high percentage of reuse and recycling of wastewater in the Marcellus shale play is a practice that industry has long asserted is a valuable means of reducing the amount of freshwater needed for well development activities.
USEPA is expected to publish a final assessment after the completion of a notice and comment period, which is currently open and concludes on August 28, 2015, and a review of the draft assessment by the Science Advisory Board Hydraulic Fracturing Research Advisory Panel. The Panel has scheduled a public meeting to conduct a review of the draft assessment from October 28 to October 30, 2015, and teleconferences to discuss the draft assessment on September 30, October 1, and October 19, 2015.
Posted on May 7, 2015
The D.C. Circuit Court of Appeals just reversed and remanded EPA’s rule allowing backup generators to operate for up to 100 hours per year as necessary for demand response. It’s an important decision that could have lessons for EPA and the regulated community across a wide range of circumstances, including eventual challenges to EPA’s proposed GHG rule.
EPA said that the rule was necessary to allow demand response programs to succeed while maintaining grid reliability. Commenters had argued that, by encouraging greater use of uncontrolled backup generators, EPA’s rule makes other generators less economic, thus creating a negative feedback loop, with less and less power generated by controlled units, resulting in greater and greater need for uncontrolled backup generators. Here’s what the Court concluded:
- EPA failed adequately to respond to the commenters’ arguments. Noting that “an agency must respond sufficiently to “enable [the court] to see what major issues of policy were ventilated,” the Court instead found that EPA “refused to engage with the commenters’ dynamic markets argument."
- To the extent EPA did respond, it was “self-contradictory”, arguing that it was not justifying the regulation on reliability grounds, even though the final rule said that it was based on reliability concerns.
- The 100-hour rule was based on faulty evidence. EPA relied on evidence that backup sources had to be available at least 60 hours to participate in a PJM “Emergency Load Response Program.” However, PJM itself noted that this minimum does not apply to individual engines.
- Finally, and perhaps most importantly, while EPA justified the rule on reliability grounds, the Court stated that:
grid reliability is not a subject of the Clean Air Act and is not the province of EPA.
This last issue is the part of the opinion that could have some bearing on judicial review of EPA’s GHG rule. The Court noted that there was no evidence that FERC or NERC had participated in the backup generator rule or provided comments to EPA. When, during the course of the rulemaking, a commenter suggested that EPA work with FERC, this was EPA’s response:
the rulemaking’s purpose was to address emissions from the emergency engines “and to minimize such pollutants within the Agency’s authority under the CAA. It is not within the scope of this rulemaking to determine which resources are used for grid reliability, nor is it the responsibility of the EPA to decide which type of power is used to address emergency situations.”
This statement did not make the Court happy:
EPA cannot have it both ways it [sic] cannot simultaneously rely on reliability concerns and then brush off comments about those concerns as beyond its purview. EPA’s response to comments suggests that its 100-hour rule, to the extent that it impacts system reliability, is not “the product of agency expertise.”
And why is this relevant for the GHG rule?
First, because EPA had better consult with FERC and NERC, so that it can defend any statements it makes in the GHG rule about its impact, if any, on reliability. Second, it’s clear that the court will not show deference to EPA’s conclusions about reliability, since that is not within the scope of EPA’s expertise.
Posted on April 1, 2015
In February 2015, the states of Connecticut, Massachusetts and Rhode Island announced their intent to seek new large-scale clean-energy projects through a multi-state procurement process. According to the draft Request for Proposal (RFP) the “essential purpose” of this procurement is to “identify any projects that offer the potential for the Procuring States to meet their clean energy goals in a cost-effective manner that brings additional regional benefits.” The draft RFP seeks bids for the delivery of Class I renewable energy projects (i.e. solar, wind, biomass, fuel cells in Connecticut, and some hydroelectric) through power purchase agreements, combined power purchase agreements and transmission upgrades, or transmission projects with clean energy delivery commitments. Because each state has different procurement laws and different definitions of “renewable energy”, the draft RFP notes that contracts for any selected projects must be negotiated with the relevant electric distribution companies (EDC) and approved in accordance with applicable state and federal laws.
To encourage the generation of renewable energy, many states have adopted Renewable Portfolio Standards (RPS) to require electric distribution companies and retail electric suppliers to include an increasing percentage of renewable energy in their mix of generation resources. Unfortunately, the RPS alone seems insufficient to encourage the development of enough renewable energy resources to address the renewable energy and climate change policies of the states. Therefore, the three New England states, as well as others, are experimenting with different methods to incentivize renewable energy generation. Given the substantial capital requirements for constructing new electric generating facilities and the need for an assured revenue stream, long-term power purchase agreements are increasingly being used to encourage the construction of new energy resources. The RFP to be issued by the three New England states seeks to attract new large scale renewable energy projects by offering successful bidders long-term energy contracts.
One question raised by this new approach to encourage the construction of reasonably-priced renewable energy resources is whether federal law preempts the states from contracting for large wholesale electric generation, despite independent state policies designed to encourage the development of more renewable energy resources. This issue has been raised in several recent federal lawsuits.
Last year, both the Fourth and Third Circuit Courts of Appeals concluded that state programs awarding long term contracts to new electric generating facilities were preempted by the Federal Power Act. In PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467 (4th Cir. 2014), the Fourth Circuit held that a fixed, twenty-year energy contract for a new Maryland generating facility was preempted by federal law. Using an RFP process, Maryland selected a company to build a power plant and sell its energy and capacity on the federal interstate wholesale market. Under the approved contract, the winning project was eligible for payments from the local EDC that amounted to the difference between the price paid in the interstate market and the amount approved in its EDC contract. The Fourth Circuit concluded that the Maryland law was field preempted because it functionally sets the rate that the generator receives for sales in the interstate energy market, an area within the exclusive jurisdiction of FERC.
Similarly, the Third Circuit, in PPL EnergyPlus, LLC v. Solomon, 766 F.3d 241 (3d Cir. 2014), held that federal law preempted a New Jersey statute under which the state solicited and awarded bids for new electric generating capacity using long-term energy capacity agreements. The Third Circuit, however, acknowledged that states have a role to play in energy markets, and stated that not every state program that has an effect on interstate electric rates will be preempted. The court explained that states may utilize measures that subsidize generators without being preempted, as long as such subsidies do not essentially set wholesale prices.
In 2013, Connecticut solicited proposals for large scale renewable energy through an RFP process. That solicitation resulted in the selection of a 250 MW wind project in Maine and a 20 MW solar project in Connecticut. Both projects were awarded long term power purchase agreements for the energy produced by these projects. A disappointed bidder, Allco Finance Limited, filed suit alleging preemption, following Nazarian and Solomon. On December 10, 2014, the district court dismissed the case, finding that a disappointed bidder lacks standing. Allco Finance, Ltd. v. Klee. Nevertheless, the court ruled on the merits. The district court concluded that the state RFP process was not preempted, rejecting Allco’s argument that the state-approved contracts set the wholesale price for energy produced by the successful bidders. The court ruled that the effect of the Connecticut program on the interstate market was at most indirect and would cause no market distortion. Allco has appealed the district court’s decision to the Second Circuit.
The use of an RFP process to encourage the development of renewable energy projects through the award of long term energy contracts is an effective way to procure lower cost renewable generation. The Connecticut Z-REC program, which awards long term Renewable Energy Credit (“REC”) contracts, has proven to be successful in driving down the cost of solar renewable energy credits from small (less than 1 MW) solar projects. In light of the federal preemption obstacles in awarding long-term wholesale electricity contracts, another approach may be to support large scale renewables by procuring long term contracts for RECs and allowing the energy price to be set by the interstate markets. Since a REC represents the renewable attribute of electricity, and not the energy itself, such procurement should avoid the preemption issues identified by the Third and Fourth Circuits. This may provide a path forward for states to pursue their clean energy goals by incentivizing larger scale renewable resources.
Posted on March 9, 2015
It is popular to grouse about how long it takes EPA to issue a rule these days. When I was at EPA in its formative years, we often went from proposal to final in just a few months. There are many reasons why the trek to final rule signing has now become so time-consuming. To name just one, advocates on all sides increasingly file lengthy comments covering technical, economic, and legal issues. And reviewing courts increasingly require EPA to fully explain its basis and purpose in response to all those comments.
While these types of delays are understandable, another type of delay is not. I am speaking of the lag between the rule’s signing by the Administrator and its publication in the Federal Register. You would think this ministerial act (the Federal Register Director isn’t authorized to re-write EPA’s rules) should be accomplished in four or five days. It almost always was when I was at EPA, and today it often is for other agencies. And sometimes these days, EPA’s signed rules get published in a few days.
But there are many exceptions, and a great example is now before us. Administrator McCarthy signed the RCRA “coal combustion residue” (CCR) final rule on December 19, 2014. It has yet to hit the Federal Register, and EPA staff announced on a recent webconference that they “hoped” it would by late March or early April. Other recent examples come to mind. The signed-to-published lag time for EPA’s 2012 CAA Oil & Gas NSPS/NESHAP rule was 121 days. The lag time for EPA’s 2014 CAA NSPS greenhouse gas (GHG) proposed rule was 110 days. It now looks like the RCRA CCR Rule will break 100.
What in the world is going on during these lengthy lag times? EPA staff will tell you that a document with numerous charts, tables, and graphs bamboozles the Federal Register people – even though the CFR has been replete with charts, tables and graphs for decades. EPA staff will also tell you (as they have for the CCR Rule) that they are fixing “typos.” But with 21st century software, can catching and correcting typos possibly take 100 days or more?
So why grouse about this? I am not suggesting that EPA staff might be making substantive, consequential changes to a final rule after the Administrator signs it. EPA does place the final rule on its Website immediately after the document is signed, so any “corrections” in the Federal Register version can be detected by a careful review. (It would be nice – for transparency’s sake – if EPA would make a practice of releasing a red-line showing exactly which “corrections” were made to the signed version during the 100+ days.)
And I am not grousing about the Federal Register publication delays per se. What bothers me is EPA’s frequent practice of refusing to release critical documents supporting the final rule – for instance, the Response to Comment (RTC) document – until the day the rule hits the Federal Register. It is this embargo – coupled with a long signed-to-published lag time – that hurts. During the recent webconference for the RCRA CCR Rule, for instance, EPA staffers made clear that the RTC and other support documents would not be released until the “hoped for” publication in late March or April.
For an agency (and Administration) that touts “transparency” at every turn, I cannot understand why EPA engages in this embargo practice. And sometimes (but not often enough), EPA does release these support documents before the rule is published in the Federal Register – so there is obviously no legal barrier to such a release.
Why should anyone care about such an embargo? As soon as a final rule is released, regulated entities often need to go into high gear to prepare for compliance. In these preparations, they need to be able to understand and interpret the rule’s provisions, many of which are often unclear or ambiguous. EPA’s RTC often provides interpretations and guidance far more lucidly than the rule’s preamble. One good example: in the RTC to EPA’s 2013 CAA “CISWI” rule, EPA provided a key interpretation of what types of activities would be deemed a “modification” triggering new source status. This interpretation appeared nowhere in the rule’s preamble and could hardly have been divined from the regulatory language. It is plainly unfair and contrary to principles of good government to hide this kind of interpretation from regulated parties for 100+ days when they are preparing for compliance.
Moreover, parties on all sides of a rulemaking (industry and public interest groups) need to begin evaluating judicial review options and theories as soon as they can after a final rule is signed. Why should they have to wait 100+ days for critical documents that are essential to their evaluation?
So dear EPA: PLEASE start releasing your RTC and other supporting documents at the same time you release your signed rule!
Posted on December 5, 2014
The 468 megawatt Cape Wind project, slated for construction in federal waters off the coast of Massachusetts in Nantucket Sound, is the first offshore wind project to be proposed and approved in the United States. The project has strong support from the Commonwealth of Massachusetts, many national, state and local environmental groups, organized labor and many others.
But being the first in an innovative venture is always difficult, and unsuccessful litigation by project opponents – some funded in large part by billionaire Bill Koch – has slowed the pace of the project. By Cape Wind’s count, thirty-two cases have been filed by project opponents. Cape Wind has ultimately prevailed in all of these actions.
A recently issued but unheralded district court decision now signals yet another legal victory for Cape Wind.
In April 2010, after a lengthy and comprehensive environmental review and permitting process which included preparation of two environmental impact statements, the U.S. Department of Interior approved the Cape Wind project. Project opponents then filed three complaints in the United States District Court for the District of Columbia.
The complaints, which were ultimately consolidated, challenged approval of the project by various federal agencies and alleged violations of the National Environmental Policy Act (NEPA), the Endangered Species Act, the Migratory Birds Treaty Act, the National Historic Preservation Act, the Outer Continental Shelf Lands Act, and the Coast Guard and Maritime Transportation Act of 2006.
Cape Wind intervened in the actions as a defendant-intervenor. Because of the project’s clean energy significance, NRDC attorneys (including me), joined by the New England-based Conservation Law Foundation and Mass Audubon, the state’s leading wildlife protection organization, filed two “friend of the court” briefs in support of the project.
In March 2014, U.S. District Court Judge Reggie Walton issued an 88-page decision granting summary judgment to the defendants, rejecting the bulk of opponents’ challenges to the federal government’s 2010 approval of the project. The court dismissed outright a host of claims that related to the government’s environmental review of the project under the National Environmental Policy Act and to the Coast Guard’s review of navigation issues under the Outer Continental Shelf Lands Act.
The court remanded two limited issues back to the federal agencies. First, it directed the U.S. Fish & Wildlife Service (FWS) to make an independent determination about whether a potential operational adjustment for the project was a “reasonable and prudent measure”. The court explained that it was unable to tell, based on the record, whether the Fish & Wildlife Service had made an independent determination or had adopted a position taken by a sister agency.
Second, the court directed the National Marine Fisheries Service (NMFS) to issue an incidental take permit covering right whales. While the NMFS biological opinion stated that the project “was not likely to adversely affect right whales” and that “incidental take was not likely to occur,” the court found that the opinion did not state that an incidental take would not occur or determine the volume of any potential take.
After the court’s decision, the two federal agencies complied with the district court’s instructions. FWS issued its independent determination with respect to the potential operational adjustment. NMFS amended the incidental take opinion to state that no take of right whales was anticipated, and thus the incidental take amount for this species could be set at zero.
However, that did not end the matter. As the district court noted in its September 12, 2014 order, “history should have forewarned that any attempt to bring this [protracted] litigation to an expeditious conclusion would prove difficult.” And as expected, the plaintiffs filed a supplemental complaint challenging the two agencies’ actions on remand.
On November 18, 2014, the district court dismissed the plaintiffs’ supplemental complaint. The court made short work of the claims, finding them all to be barred – some because they had been previously waived or abandoned and some because the Court had previously considered and rejected them. Indeed, the court noted that some of the claims were “difficult to understand.” With that decision, this chapter in the long string of legal challenges was concluded, at the district court level at least. The plaintiffs filed a notice of appeal yesterday.
Meanwhile, the Cape Wind project continues to move forward. In July, the U.S. Department of Energy issued a conditional loan guarantee commitment for the project, the first step toward securing a $150 million loan guarantee. In August, the project selected its lead construction contractors. Construction is expected to proceed in 2015.
And Cape Wind’s example has spurred forward movement in the U.S. offshore wind industry. Currently, there are some fourteen offshore wind projects in an advanced stage of development along the East Coast and elsewhere, representing 4.9 gigawatts of potential renewable electricity capacity. Despite the protracted litigation, it’s my hope that Cape Wind, buoyed by its legal victories, will herald the start of a new renewable energy industry that will fully and sustainably tap into the United States’ huge offshore wind resource.
Posted on December 2, 2014
Back in September 2008, TransCanada Keystone Pipeline LP (TransCanada) filed what it probably thought at the time was a straightforward, routine application for a Presidential permit to build its Keystone XL pipeline. As almost everyone knows now, that pipeline would deliver thousands of barrels of Canadian crude oil to refineries on the U.S. gulf coast. The project appeared to be straightforward because the environmental review process required by the National Environmental Policy Act (NEPA) has been honed over many years. If not exactly expeditious, the NEPA process is well known and often used. And the project appeared to be routine because there are many pipelines that already cross U.S. territory.
Yet, six years later, there still is no final decision on a permit. The review process has ballooned into an intricate one, attracting legislative and judicial attention and intervention at both the state and federal levels, not to mention increased public awareness. Normally, one would expect increased public attention and awareness to lead to better decision-making and hopefully that will be the case here. My question, though, is whether this public participation could have been integrated into the NEPA process earlier. A follow-up question might be whether it would have mattered once politics took over.
The delay in completing this project review is undoubtedly frustrating for many and has created a “moving target” conundrum with many other decision-makers now involved. Even with a decision by the Nebraska Supreme Court and a final Presidential decision on the permit, the congressional and federal legal challenges are unlikely to end. Has this project become so politicized that there can be no public confidence in the eventual outcome? Would there have been a better way to encourage public participation earlier?
Nebraska could have gotten involved sooner. The federal NEPA regulations allow a State or local agency “which has jurisdiction by law or special expertise with respect to any environmental impact involved in a [proposed project]” to become a cooperating agency, with the federal lead agency conducting the federal NEPA review. In 2009, the Department of State invited local governments to weigh in on the permitting process for the Keystone XL pipeline under NEPA by becoming a cooperating agency.
At that time, the pipeline route debate had not yet arisen and Nebraska could still participate in the NEPA process by providing comments. In addition, the federal NEPA regulations normally require a cooperating agency to use its own funds. Nebraska’s ability to fund its own NEPA-like review of the project was severely limited since the state had no similar NEPA-like requirement or source of funding at that time. Given the lack of controversy early on, the extra expense of becoming a cooperating agency seemed unnecessary when the opportunity to offer comment was an option.
Would Nebraska involvement at that earlier time have made a difference? It’s hard to say. Opposition to the pipeline route in Nebraska only started to come together when the Final Environmental Impact Statement (EIS) came out in August of 2011 and TransCanada began contacting local landowners to obtain easements. The growing opposition led to Nebraska legislation essentially creating a cooperating role for Nebraska by providing adequate funding for preparation of a report to supplement the federal EIS. That report was published in January 2013.
In addition to Nebraska’s actions, the U.S. Department of State determined that more information was needed about alternative routes to avoid the environmentally sensitive Sand Hills region of Nebraska. This prompted Congress to adopt a provision forcing Presidential action on the 2011 EIS within 60 days.
The President then denied the permit for the reason that it didn’t allow sufficient time to review the proposed alternative route through Nebraska. TransCanada re-applied in May 2012 with a proposed new route through Nebraska. This led to more state legislation, state legal challenges, a supplemental report issued by Nebraska in 2013, and a Final Supplemental EIS issued by the U.S. Department of State. But, there’s still no permit decision, as most parties are awaiting a final decision by the Nebraska Supreme Court on the constitutionality of the state legislation.
This looks more like a schizophrenic chess match than responsible government. Is it just government avoiding a difficult and controversial decision? But, with so many wrenches thrown into this particular NEPA review, how could we expect the process to reach a final resolution in a timely manner? It is rare these days to find any public policy being made in a forthright and timely manner without competing vested interests impeding the administrative process in any number of “legitimate” ways. Unfortunately, environmental issues are no different in this respect than immigration or health care. The Keystone XL pipeline is only one example where our Constitutional construct has given us lots of “checks” without much balance.
Posted on November 4, 2014
Over 30 earthquakes jolted the area in and around the City of Azle, Texas —20 miles north of Fort Worth—last November through January. In response to citizen concerns, the Texas House Committee on Energy Resources created a Subcommittee on Seismic Activity to investigate whether there was a link between earthquakes and increased oil and gas production and disposal wells. On August 12, the Railroad Commission of Texas, with support from both the Texas oil and gas industry and environmental groups, proposed rules that would require companies to do a seismic survey before obtaining permits for new oil and gas disposal wells—so-called Class II injection wells. On October 28, 2014, the Railroad Commission unanimously voted to finalize that proposal.
Presently, the state has more than 3600 active commercial injection wells used for the disposal of oil and gas wastes. The rules require applicants for new oil and gas disposal wells to provide additional information, including logs, geologic cross-sections, and structure maps for injection well in an area where conditions exist that may increase the risk that fluids will not be confined to the injection interval. Those conditions include, among other things, complex geology, proximity of the base rock to the injection interval, transmissive faults, and a history of seismic events in the area as demonstrated by information available from the USGS. The rules also clarify that the Railroad Commission may modify, suspend, or terminate a permit if fluids are not confined to the injection interval, that is, if it poses a risk of seismic activity. The effect of these rules will be not only to regulate oil and gas disposal activities to address potential seismic effects, but also to generate data that may be useful in determining whether and to what extent to further regulate those activities. The rules also may serve as a model for other states concerned about the seismic effects of oil and gas waste disposal.
Posted on October 31, 2014
“Elmer Gantry,” a noir classic novel by Sinclair Lewis and a 1960 film, features a tortured central character with the word “love” tattooed on the knuckles of one hand and “hate” on the knuckles of the other hand. The vision of the hands together intertwined as symbols of the dilemma of the conflicted protagonist’s internal battles is evocative of the disconnect between our deep and undeniable thirst for energy and our disdain for the manner by which it is produced and delivered to us.
A History of Options:
Coal fired power plants are coming under heavy fire as the U.S. seeks to significantly reduce air emissions. Global climate change, health impacts and a series of other negative effects on the ecosystem are cited as bases for accelerated retirements of these generation stations. No doubt coal mining is a tough and dirty business; yet for two centuries it has provided the backbone of the development of electric power plants and the extraordinary benefits of electric energy. How to reconcile this history with the current political climate? How do we transition from coal as a major US fuel source, one that provides domestic supply and multiple benefits in employment, tax base, and economic activity?
Likewise, hydroelectric generation is enshrined in the transformation of much of the West in the songs of Woody Guthrie, as a magnificent contribution to our development as a nation. And, the desirability of hydroelectric generation is magnified when the only “issue on the table” is the greenhouse gas impacts of generation. Yet, the impacts of hydroelectric development have had deleterious effects on fish, landscapes, and water supply. And, as drought strangles much of the West, there is a struggle over whether to tear down the much admired, in fact almost “loved,” green dams of the New Deal Era. The question at issue here is which side is good and which is evil, and the answer is “it all depends.”
Another love-hate relationship lies with the nuclear generation fleet. From the standpoint of greenhouse gas emissions, the nuclear generation fleet is a winner. Yet to some anti-nuclear interests, the nuclear stations (for the most part, forty years or older) are the devil incarnate, and subject to exorcism. Yet, these facilities provide nearly 20 per cent of the electric power of the country. So again, the desire for a clean electric supply and antipathy to the technology clash. In this case, dealing with the aftermath of closing a nuclear generation station includes the significant and seemingly intractable problem of nuclear waste storage and disposal, leading to more profoundly difficult questions and concerns.
Another emotional “generation war” is centered on the role of natural gas fired generation. Once again, there are epic clashes over gas. Gas is ever more obviously abundant and relatively desirable from an environmental standpoint. However, extreme passions have been aroused by gas production-related issues like hydraulic fracturing, new pipeline capacity and fears about safety, and harmful environmental effects from natural gas drilling, production, transportation and distribution. Despite the fact that natural gas fueled generation has filled approximately a quarter of the nation’s electric generation demand for many years, and is likely to be a major solution to the shift from coal, nuclear and some hydroelectric plants, the heated anti-fracking debate continues. Thus, the struggle continues between “good,” (by those who see gas as a solution to the need for reliable generation) and “evil” (by those who oppose the drilling, development and delivery impacts of any form of hydrocarbon-related fuel). Indeed, the politics, sophistication and interest of high profile opponents has elevated the bitter war of words and politics to a new level.
Finally, the role of renewables as a source of generation to replace nuclear, coal and other forms of generation would, superficially, seem to be uncontroversial. Yet once the specifics of a project become known, opposition to the project grows. Like politics, all projects are local. Wind power towers, with associated land use, avian impacts, noise, reliability and transmission-related needs become the object of ire for interests that may not benefit from the projects. Likewise, solar projects with land use, impact on wildlife water use and other hot-button issues may precipitate other battles. The beauty of the project is in the eye of the beholder and beneficiary.
The Paradox Ahead
Overarching all these projects are difficult issues associated with transmission capacity and cost, reliability, taxation, employment and overall local economic dependency. And uncertainty about the need for new generation makes things worse: why tolerate potentially disruptive technologies if efficiency increases and other factors means that new generation isn’t needed? In light of the volatile, complicated, politically charged environment, the struggle for answers and stability will continue. As long as our society remains conflicted, these issues will continue unabated to be “front page,” and lawyer and politician intensive. The search for rational solutions to meet the needs of the country for reliable, safe, environmentally acceptable electric generation must continue for the nation to survive and thrive, despite the pain, cost and compromise necessary. And like the soul of “Elmer Gantry,” we must ultimately cease to be at war with ourselves to survive.
Posted on October 20, 2014
In the mid-1970’s, the nation faced long gas lines, the rationing of heating oil supplies, 55 miles per hour speed limits on the highway, the curtailment of holiday lighting, and the uncertainty of sufficient supplies of petrochemical feed stocks for industry. Pundits routinely predicted dire forecasts of shivering residences, financial dislocations, and geo-political struggles between the United States and the OPEC suppliers. Against this backdrop Congress banned most crude oil exports under the Energy Policy and Conservation Act of 1975.
With the emergence of unconventional drilling techniques, colloquially described by the shorthand term ”fracking”, the nation recently began to see growing supplies of natural gas and oil. Last year’s Annual Meeting of the American College of Environmental Laws featured a timely panel discussion on the environmental and economic issues associated with (1) the conversion of underutilized LNG import terminals into LNG export terminals, (2) the development of massive port terminals in Washington, Oregon, and Louisiana for coal exports to Asia, (3) the increased emission of the potent GHG methane from the higher level of drilling activity, (4) the downstream effects on rural communities that have become the homes of these “shale plays,” (5) the construction of massive mid-stream facilities and transmission lines ( like the Keystone XL pipeline in areas thought to be sensitive because of their habitat for endangered species and their location near valuable water supplies), and (6) the safety risks of the increased use of rail transport for crude oil. An executive with one of the major oil companies reports that oil production in the United States has jumped 50% since early 2011. The Energy Information Administration recently stated that United States oil production is expected to reach its highest level since 1970; this increase is occurring at a time when domestic oil consumption is declining.
Major oil companies, the U.S. Chamber of Commerce, the American Petroleum Institute and others have called for an end to the 40-year old ban on oil exports. Those calls have coincided with increased congressional interest from both House and Senate members in lifting the ban.
With the “sea change” in the domestic oil production picture, the administration of President Obama has begun to look at possible repeal of the 40 year- old - ban on crude oil exports. Energy Secretary Ernest Moniz recently addressed the Council on Foreign Relations on the current efforts to assess the “very different” oil market when the ban went into effect. A link to his 50 minute presentation on You Tube is found below. (The Secretary’s presentation touches on a wide range of topics, but his discussion of crude oil exports begins approximately 20 minutes into the address). Secretary Moniz did not give a time frame for a decision, noting that the nation remains a significant importer at this time. He said the final decision may turn on the market impacts. As of the date this blog piece is written, the price for oil has reached a very low point, in part due to the glut of new domestic supplies, to a level that calls into question the economics of new well completions with unconventional drilling techniques. The 50 minute speech also touches on other subjects, including the progress made in reducing methane emissions from leaking infrastructure, greater water recycling, more effective well completion requirements, as well as the improvements in the solar energy as a way to meet the nation’s goal of a low-carbon economy, and the plans for the U.S. to announce its climate change pledge in the first quarter of 2015.
Video: Energy Secretary Ernest Moniz on U.S. Energy Policy
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.”