Restoring old mill hydro sites and FERC licensure

Friday, February 5, 2016

Suppose you own an existing water powered mill complex whose hydromechanical facilities have not been operational for decades.  You would like to develop a hydropower project at the site, using the existing dam, headrace, and headgates, plus new equipment including two small generators, penstocks, and appurtenant facilities, to provide electricity to your home and workshop.  Do you need a license from the Federal Energy Regulatory Commission?

In the case of the Egnaczak Net Zero Hydro Project proposed for the outlet of the Hoosic River in Cheshire, Massachusetts, the FERC concluded that section 23(b)(1) of the Federal Power Act requires that project's owners to obtain a license for the project's construction, maintenance, and operation.  Proposed by Kenneth and Susan Egnaczak, the Egnaczak Net Zero Hydro Project would have a total generating capacity of 10.7 kilowatts.

Pursuant to section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
The fourth prong itself has three main elements: project located on a Commerce Clause stream, post-1935 construction or modification, affecting interstate commerce.  In this case, FERC concluded that the Egnaczak project satisfied the fourth prong.

First, FERC found that the Egnaczak project is located on a Commerce Clause stream.  Under a 1965 Supreme Court ruling, for purposes of Federal Power Act section 23(b)(1), Commerce Clause streams are the headwaters and tributaries of navigable waters of the United States.  While FERC declined to determine whether the Hoosic River is navigable at the site of the project, it concluded that downstream segments of the Hoosic are navigable, as is the Hudson River into which the Hoosic flows.

Second, FERC next found that installing new hydroelectric generating capacity constitutes post-1935 construction within the meaning of Federal Power Act section 23(b)(1). 

Third, FERC found that the project would offset both electrical and heating needs that would have been otherwise supplied by the interstate grid -- and thus that the project would affect the interests of interstate commerce.  A footnote notes, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)."

FERC concluded that because the project would be located on a Commerce Clause stream, would be constructed after 1935, and would affect interstate commerce through its connection to the interstate grid, Section 23(b)(1) of the Federal Power Act requires Kenneth and Susan Egnaczak to obtain a license for the project's construction, maintenance, and operation.  The FERC order also suggests the project may be eligible to obtain an exemption from licensing as a small hydroelectric power project of 10 megawatts or less, and encourages the applicants to investigate the requirements for securing an exemption from licensure.

E2Tech solar forum 2016

Wednesday, February 3, 2016

Today the Environmental and Energy Technology Council of Maine, better known as E2Tech, held its E2Tech forum on solar energy.

A panel of solar policy experts shared their perspectives on the issues facing Maine.  The panel included:
Panelists and audience members discussed some of the recent and ongoing solar energy policy discussions and outcomes in Maine, including a stakeholder process before the Maine Public Utilities Commission to explore an alternative policy complementary to net metering.  That process is expected to wrap up this winter with a report to the legislative committee with jurisdiction over energy matters.

The event also featured Preti Flaherty's launch of its First Light initiative.  Grounded in the Preti team’s experience helping consumers benefit from distributed or “behind the meter” generation, the firm has created a special focus on the commercialization of solar power by and for all consumers.  This strategic initiative will help qualified new entrants, as well as larger, existing companies, navigate legal and business challenges to harness the power of the sun. It will also help site owners participate in solar energy as project hosts, through site leasing and power purchase agreements or other arrangements.  Contact Todd Griset for more information about qualifying for the Preti First Light program.

FERC requires licensure of Alaska hydropower project

Monday, February 1, 2016

What happens when federal hydropower regulators discover an unlicensed project subject to their jurisdiction?  A recent case involving a dam at a remote Alaskan fish hatchery ended with an order requiring the project owner to pursue licensure.

At issue is the Hidden Falls Lake Project, located within the Tongass National Forest on Kasnyku Bay on the eastern shore of Baranof Island near Sitka, Alaska.  The project is owned by the Alaska Department of Fish and Game, who installed a 250-kilowatt generator and related equipment in 1982 to power its Hidden Falls fish hatchery.  (A nearby larger Kasnyku Lake project contemplated by the federal government in 1969 never came to fruition.)

Most non-federal hydropower projects in the U.S. must be licensed by the Federal Energy Regulatory Commission.  Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project without a still-valid pre-1920 federal permit must be licensed if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.
Part of the Hidden Falls Lake project -- the intake, penstock, 250-kW hydroelectric generator, powerhouse, and distribution lines -- are located on U.S. Forest Service lands. The Forest Service’s documentation states that a minor license application for the Hidden Falls Lake Project was filed with the Commission in 1981, but the Commission said it did not have any records of this application or of any subsequent Commission jurisdictional determination for this project.

But FERC did apparently know about the project.  In 1989, seven years after the project's generator was installed, the Commission initiated an investigation into the jurisdictional status of the project, suggesting it was "unlicensed" or "unauthorized."  Yet that unlicensed hydropower project investigation docket then went dormant until 2015.  Last year, the Forest Service informed the Commission that it had identified the project while conducting environmental reviews in support of a renewal of the Alaska agency's special use permit for the hatchery.  Thus the investigation resumed.

The Commission issued its final order in the case on January 28, 2016.  Because the project intake, penstock, hydroelectric generator, powerhouse, and distribution lines occupy public lands of the United States, the Commission concluded that the Alaska agency must obtain a license for construction, maintenance, and continued operation of the Hidden Falls Lake Project.  The Commission ordered the Alaska agency to file within 90 days a schedule for submitting a license application within 36 months.

If a small hydropower project on a remote Alaskan island is subject to FERC licensure, how many other unlicensed hydropower projects might be out there?  How many other unlicensed hydropower projects might there be on Forest Service or other federal lands?  While FERC investigations of unlicensed hydropower projects are relatively rare, with most years seeing only a handful of public active investigations, could there be other existing projects like the Hidden Falls Lake Project?

RGGI states comment on Clean Power Plan

Friday, January 29, 2016

The nine Northeastern and Mid-Atlantic states participating in the Regional Greenhouse Gas Initiative (RGGI) have submitted joint comments to the United States Environmental Protection Agency in connection with its Clean Power Plan rule.

RGGI is a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce carbon dioxide emissions from the electric power sector.  The program establishes a regional cap on the amount of carbon dioxide that power plants can emit through the issuance of a limited number of tradable allowances.  RGGI's first three-year compliance period began on January 1, 2009, making it the nation’s first market-based emissions trading program to reduce greenhouse gas pollution.

On August 3, 2015, the EPA announced its "Clean Power Plan," new regulations limiting power plant carbon emissions under Section 111(d) of the Clean Air Act.  While states are free to build their own compliance plans, the rule establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired electric generating units.  The rule also encourages states and regions to work together in developing compliance plans.

States are now tasked with developing their compliance plans.  The Clean Power Plan gives states until September 6, 2016, to either submit a final carbon-cutting plan or to submit an initial plan along with a two-year extension request.  Many observers have noted that for states already participating in RGGI, that program may be able to serve as a mechanism for Clean Power Plan compliance.  This prospect is natural, as RGGI and the Clean Power Plan share some common goals and features.

This week, the nine RGGI states submitted joint comments to the EPA on the Federal Plan (FP) and Model Rules (MR) proposed as part of the Clean Power Plan.  In those comments, the RGGI states "welcome EPA's continued recognition that well-designed multi-state, market-based programs like RGGI can deliver cost-effective emissions reductions."

In an accompanying press release, the RGGI states note their own "track record of success."  As cited in the joint comments, the "RGGI states have seen benefits to the economy and public health, as well as consumer savings, experiencing 8 percent GDP growth across the region while reducing power sector carbon pollution by more than 40 percent since 2005," while maintaining electric reliability.

Based on this experience, the RGGI states encouraged EPA to select mass-based approaches as the most cost-effective, transparent, and reliable way to achieve emission reductions.  (Mass-based approaches set limits on the total mass of carbon allowed to be emitted -- like 100 million tons.  By contrast, rate-based approaches might limit the rate of carbon emissions per unit of useful electric energy.)

Recognizing that trading platforms can play an important role in markets, increasing participation, access, and liquidity, the RGGI states urged EPA to "adopt a trading platform that is flexible and customizable to encourage broader trading markets."

The RGGI states also asked EPA to encourage auctioning of carbon allowances, and reinvestment of the auction proceeds.  In so doing, the RGGI states pointed to their own reinvestment of RGGI auction proceeds in efficiency and consumer relief.

Finally, the RGGI states encouraged EPA to prevent "leakage" of carbon emissions from existing sources to new sources, by including new sources in a mass-based program or some other equally effective alternative method of allocation.

With states now working to develop Clean Power Plan compliance strategies, how will the RGGI experience shape state plans to comply with the Clean Power Plan?

NERC suggests Clean Power Plan reliability considerations

Thursday, January 28, 2016

The electric reliability organization for North America has issued an assessment of reliability considerations it thinks state electricity and environmental regulators should take into account in crafting state plans to comply with the Clean Power Plan.

The North American Electric Reliability Corporation (NERC) is a not‐for‐profit regulatory authority whose mission is to assure the reliability of North America's bulk power system.

Last year, the U.S. Environmental Protection Agency (EPA) issued its Clean Power Plan, a final rule limiting carbon dioxide emissions for existing electric generation facilities.  States are expected to prepare individual or collaborative plans to comply with the regulation.  Because reducing the carbon intensity of electric power generation is the goal, EPA expects that some plans will include a shift from coal-fired power plants to less carbon-intensive sources.  As NERC wrote in its assessment:
The BPS is already undergoing a broad transformation with retirements of coal units and some nuclear units, and additions of resources fueled by natural gas, wind, and solar. Distributed generation, energy efficiency, and demand response are also changing the way in which system planners must account for resources. The CPP has the potential to hasten the transformation of the electric system started by market and political factors such as natural gas supply and pricing and federal and state policy decisions with respect to renewables and energy efficiency and other environmental regulations.
But reliability is a key issue at stake in any shift in the portfolio of generating resources.  The Clean Power Plan rule explicitly requires that states consider reliability as part of their plans.

NERC's assessment, Reliability Considerations for Clean Power Plan Development, presents its view of "aspects of plan design that need to be considered to reliably accommodate this broad transformation."  NERC's ten key reliability considerations are:

  • State coordination with system planning entities - planners and coordinators working together
  • Essential reliability services - "In order to maintain an adequate level of reliability through this transition, generation resources need to provide sufficient voltage control, frequency support, and ramping capability — essential components to the reliable operation of the BPS. It is necessary for policy makers to recognize the need for these services by ensuring that interconnection requirements, market mechanisms, or other reliability requirements provide sufficient means of adapting the system to accommodate large amounts of variable and/or distributed energy resources (DERs)."
  • Timing considerations for energy infrastructure development - "Retirements can happen quickly, but adequate replacement facilities must be in service prior to retirement. As natural gas‐fired generation replaces coal‐fired generation the requisite timeline for natural gas pipeline infrastructure becomes even more relevant."
  • Electricity imports and exports - "If a state intends to use resources from nearby states as part of a compliance strategy, it is important to determine if the necessary transmission capability is available to reliably transport electricity from those resources."
  • Change in generator cycling and operations - coal plants may serve more seasonal peak demands, so "states should take account of changes in maintenance requirements likely due to cycling and the risk of increased forced outages of these coal‐fired plants. Additionally, increased and sufficient coordination between gas and electric system operators becomes much more critical to ensure adequate amounts of fuel are available."
  • Reserve margin assessment - "As more variable and energy ‐ limited resources are added, the system will likely require additional reserve capacity to maintain a similar level of reliability compared to a system with all conventional generation."
  • Energy efficiency - "Given that EE can be used as a potential CPP compliance tool, it is important that states evaluate the realistic potential for EE to displace load and the likely duration of those impacts. Shorter term EE measures may serve as a potential bridge to meet CPP requirements."
  • Emissions trading - "In general, emissions trading promotes additional reliability compliance options by effectively broadening the compliance region as well as the availability of allowances and credits. However, some resource options that might be assumed available through emissions trading may not be, due to another state’s plan. Because trading is optional, states should coordinate to ensure the most beneficial approach of trading is considered."
  • Reliability safety valve - "States must understand how the Reliability Safety Valve works and its limits, recognizing that it cannot be used as a planning tool to meet CPP requirements."
  • North American and European precedents - states should review carbon market precedents like RGGI and shifts in Canada and Europe toward renewable and distributed resources as case studies for potential strategies, lessons learned in implementation, and insights as they develop their plans.
Some states are already developing Clean Power Plan compliance plans.  Meanwhile, judicial challenges have been filed.  Initial plans are due to the EPA later this year.

Court ruling cuts demand response uncertainty

Tuesday, January 26, 2016

Yesterday the U.S. Supreme Court issued an opinion upholding federal regulation of the compensation paid for wholesale electricity demand response.  The Court's opinion, FERC v. Electric Power Supply Assn., hinges on the distinction between wholesale and retail sales of electricity.  It provides the latest look at the boundary between federal and state jurisdiction over the electric grid.

Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce."  Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale.  Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.

The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745.  Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators.  Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response.  The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction.  FERC appealed this decision to the Supreme Court.

As described in the Supreme Court opinion, the appeal presented two legal issues:
First, and fundamen­tally, does the FPA permit FERC to regulate these demand response transactions at all, or does any such rule impinge on the States’ authority? Second, even if FERC has the requisite statutory power, did the Commission fail to justify adequately why demand response providers and electricity producers should receive the same compensa­tion? The court below ruled against FERC on both scores. We disagree.
In analyzing the first issue, the majority found that compensation for demand response directly affects wholesale prices -- "Indeed, it is hard to think of a practice that does so more."  The majority found, "A FERC regulation does not run afoul of section 824(b)’s prescription just because it affects―even substantially―the quantity or terms of retail sales."  The Court finally noted that FERC had offered substantial reasoning and arguments in support of its conclusion that demand response should be paid comparably to generation, and thus that FERC's actions satisfied the applicable standard that they not be "arbitrary and capricious."

The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision.  Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling.  Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act.  With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.

US Supreme Court upholds wholesale demand response

Monday, January 25, 2016

The Supreme Court of the United States has issued an opinion upholding regional electricity grid operators' ability to operate wholesale demand response programs under federal authority.  In that opinion, FERC v. Electric Power Supply Assn., the Supreme Court reversed a lower court's decision invalidating the Federal Energy Regulatory Commission's regulation of electricity demand response.   While further evolution of demand response will continue, the Supreme Court's 6-to-2 ruling puts regional wholesale demand response programs back on surer footing after the uncertainty injected by the lower court's previous ruling.  A grid portfolio including some degree of demand response can provide beneficial environmental, reliability, and economic effects compared to pure generation.  It appears relatively more likely that existing regional wholesale demand response programs may continue to operate under federal authority, and relatively less likely that a new state-driven demand response paradigm will arise.

As described in the Supreme Court opinion, wholesale electricity demand response programs pay consumers for commitments to reduce their consumption of electricity during peak demand periods or other times of scarcity or high prices.  For about 15 years, wholesale market operators have increasingly adopted wholesale demand response programs, with the blessing of both Congress and the FERC.  In 2011, the FERC issued its Order No. 745, establishing a rule requiring market operators to pay the same price to cost-effective demand response providers for conserving energy as to generators for producing it. 

But that order was challenged by an association of generators, among others.  In May 2014, the D.C. Circuit Court of Appeals issued a ruling in Electric Power Supply Association v. Federal Energy Regulatory Commission vacating Order No. 745.  Its chief logic was that FERC lacked authority to issue the order on jurisdictional grounds -- because in the lower court's view, Order No. 745 directly regulates the retail electric market.  Under the Federal Power Act, FERC is authorized to regulate "the sale of electric energy at wholesale in interstate commerce," but cannot regulate "any other sale" (i.e. any retail sale) of electricity.

But today's Supreme Court ruling held that the Federal Power Act does provide FERC with the authority to regulate wholesale market operators' compensation of demand response bids.  The Court divided its analysis of this point in three parts.

First, the Supreme Court held that the practices at issue directly affect wholesale rates.  In the Court's words, "Wholesale demand response is all about reducing wholesale rates; so too the rules and practices that determine how those programs operate."

Second, the Supreme Court noted that FERC has not regulated retail sales.  "Here, every aspect of FERC's regulatory plan happens exclusively on the wholesale market and governs exclusively that market's rules.  The Commission's justifications for regulating demand response are likewise only about improving the wholesale market."  Putting the first and second sets of conclusions together, the Court found that the rule established by Order No. 745 complies with the plain terms of the Federal Power Act.

Third, the Court noted that adopting a contrary view would conflict with the core purposes of the Federal Power Act: "The FPA should not be read, against its clear terms, to halt a practice that so evidently enables FERC to fulfill its statutory duties of holding down prices and enhancing reliability in the wholesale energy market."

The Supreme Court also addressed an alternative holding by the D.C. Circuit Court that the Order No. 745 compensation scheme is arbitrary and capricious under the Administrative Procedure Act.  The Supreme Court noted that its "important but limited role" in reviewing FERC's decision "is to ensure that FERC engaged in reasoned decisionmaking."  Noting FERC's detailed explanation of its choice to compensate demand response providers at LMP, the same price paid to generators, and its lengthy responses to contrary views, the Supreme Court held that "FERC's serious and careful discussion of the issue satisfies the arbitrary and capricious standard."

Justice Kagan delivered the Court's opinion, joined by Chief Justice Roberts and Justices Kennedy, Ginsburg, Breyer, and Sotomayor.   Justice Scalia filed a dissenting opinion, in which Justice Thomas joined, noting his belief that the Federal Power Act prohibits the FERC from regulating the demand response of "retail purchasers of power."  Justice Alito did not participate in the case.

The case now returns to the D.C. Circuit for "further proceedings consistent with this opinion." If Order No. 745 stands and FERC retains jurisdiction over the compensation paid to wholesale demand response market participants, it seems likely that existing regional wholesale demand response programs will continue to operate under federal authority.  As the Supreme Court found, these wholesale demand response programs can provide significant consumer savings when properly implemented.  How will demand response continue to evolve in the wake of FERC v. EPSA?  How does this decision reshape the boundary between wholesale (federal) and retail (state) jurisdictions?  What's next for demand response?

FERC staff guidance for Clean Power Plan modeling

Wednesday, January 20, 2016

Staff of the U.S. Federal Energy Regulatory Commission have issued a white paper presenting guidance principles for modeling state plans to comply with the U.S. Environmental Protection Agency's Clean Power Plan carbon regulations from existing fossil fuel-fired electric power plants.

The EPA issued the Clean Power Plan on August 3, 2015 as a regulation under Section 111(d) of the Clean Air Act.  The Clean Power Plan limits carbon dioxide emissions from existing fossil fuel-fired electric power plants.  The final rule provides state specific goals for carbon dioxide emissions from affected electric generating units, including interim emissions goals from 2022 to 2029 and a final goal for 2030.

Due to congressional concern that environmental regulations not jeopardize the reliability of the electric grid, each covered state must demonstrate that it has considered reliability issues in developing its plan.  That consideration of reliability is certain to include modeling.  The Federal Energy Regulatory Commission has entered into an agreement with EPA and the U.S. Department of Energy to coordinate certain activities to help ensure continued reliable electricity generation and transmission during the Clean Power Plan's implementation.

In furtherance of that mission, on January 19, 2016, staff of the Commission released an 18-page white paper identifying four guiding principles that may assist transmission planning entities in conducting effective analysis of the Clean Power Plan and associated state, regional, or federal compliance plans.

These guiding principles address four areas:
  • Transparency and stakeholder engagement: "transparency and stakeholder engagement in model development, model inputs and study designs can help identify policy alternatives and effectively evaluate assumptions, while also improving coordination across transmission planning regions."
  • Study methodology and interactions between studies: "incorporating changes to current study methodologies can allow transmission planning entities to more effectively assess the impact of the CPP and associated compliance plans."
  • Study inputs, sensitivities and probabilistic analysis: "using study inputs that account for uncertainty and test for sensitivity can help effectively assess the impact of the CPP and associated compliance plans."
  • Tools and techniques: "adopting new modeling tools and techniques may help transmission planning entities better assess the overall impact of the CPP and associated compliance plans."

The FERC staff white paper notes that while "effectively evaluating the impacts of the CPP may present challenges, these challenges can be mitigated by using appropriate modeling tools and techniques."  Under the Clean Power Plan, states have until September 6, 2016, to submit either a final carbon-cutting plan or to request a two-year extension and to submit an initial plan for EPA review.

Maine utility requests net metering review

Friday, January 15, 2016

Maine transmission and distribution company Central Maine Power Company has asked the Maine Public Utilities Commission to review whether the state's net metering program should continue or be modified.

Maine allows customers with qualifying distributed electric generation to net the power they produce against their consumption of power from the grid.  The Maine Public Utilities Commission adopted rules governing this "net energy billing" or net metering arrangement.  Most customer-scale solar photovoltaic projects in Maine rely on net energy billing, including those located in the service territory of utility Central Maine Power or CMP.

One provision of those rules, found in Section 3(J) of Chapter 313, provides for regulatory review of net metering once a utility reaches a threshold of installed net metering capacity:
A transmission and distribution utility shall notify the Commission if the cumulative capacity of generating facilities subject to the provisions of this Chapter reaches 1.0 percent of its peak demand. Upon notification, the Commission will review this Chapter to determine whether net energy billing pursuant to this Chapter should continue or be modified.
On January 14, 2016, CMP filed a letter with the Maine Commission requesting that the Commission undertake the review of net energy billing described in Section 3(J) of Chapter 313.  In support of that request, CMP notes:
As of the end of calendar year 2015, the cumulative capacity of the generating facilities for which CMP has net energy billing agreements under Chapter 313 is approximately 1.04% of CMP’s annual peak demand. The 1.04% is based upon the ratio of 16.261/1,565.300, where the numerator is the megawatts of nameplate capacity of contracted net energy billing facilities and the denominator represents the Company’s 2015 annual hourly peak demand.
The Maine Public Utilities Commission has docketed CMP's request as 2015-00008.  At the same time, the Commission is concluding a months-long legislatively mandated stakeholder process to consider alternatives to net energy billing, after which the Commission is scheduled to present a report to the state's legislative energy committee.

These two proceedings have different direct origins, but their effects could be similar.  CMP's letter under Chapter 313 says it was triggered by growth of enrolled net metering capacity, while the stakeholder process resulted from a direct legislative requirement.  Nevertheless both proceedings may affect the future of net metering in Maine.

Climate and energy in 2016 State of the Union

Wednesday, January 13, 2016

President Obama delivered his final State of the Union address on January 12, 2016.  The White House has posted his remarks as prepared for delivery to Congress.  Climate change, and related energy and environmental issues, formed a prominent theme in this year's speech.

The White House.

Climate change first surfaced in the 2016 State of the Union as part of one of four "big questions" President Obama posed for the nation.
Second, how do we make technology work for us, and not against us -- especially when it comes to solving urgent challenges like climate change?
After announcing a "moonshot" medical research effort to cure cancer to be led by Vice President Joe Biden, President Obama said, "We need the same level of commitment when it comes to developing clean energy sources."

He then spent several minutes addressing climate change directly.  First, he noted effective consensus that climate change is a topic worth tackling:
Look, if anybody still wants to dispute the science around climate change, have at it. You will be pretty lonely, because you’ll be debating our military, most of America’s business leaders, the majority of the American people, almost the entire scientific community, and 200 nations around the world who agree it’s a problem and intend to solve it.
He then touted the economic and environmental effects of investment in renewable and distributed generation and energy storage:
But even if -- even if the planet wasn’t at stake, even if 2014 wasn’t the warmest year on record -- until 2015 turned out to be even hotter -- why would we want to pass up the chance for American businesses to produce and sell the energy of the future?

Listen, seven years ago, we made the single biggest investment in clean energy in our history. Here are the results. In fields from Iowa to Texas, wind power is now cheaper than dirtier, conventional power. On rooftops from Arizona to New York, solar is saving Americans tens of millions of dollars a year on their energy bills, and employs more Americans than coal -- in jobs that pay better than average. We’re taking steps to give homeowners the freedom to generate and store their own energy -- something, by the way, that environmentalists and Tea Partiers have teamed up to support. And meanwhile, we’ve cut our imports of foreign oil by nearly 60 percent, and cut carbon pollution more than any other country on Earth.
Gas under two bucks a gallon ain’t bad, either.
President Obama then called for changes to transition to clean energy sources:
Now we’ve got to accelerate the transition away from old, dirtier energy sources. Rather than subsidize the past, we should invest in the future -- especially in communities that rely on fossil fuels. We do them no favor when we don't show them where the trends are going. That’s why I’m going to push to change the way we manage our oil and coal resources, so that they better reflect the costs they impose on taxpayers and our planet. And that way, we put money back into those communities, and put tens of thousands of Americans to work building a 21st century transportation system.
Now, none of this is going to happen overnight. And, yes, there are plenty of entrenched interests who want to protect the status quo. But the jobs we’ll create, the money we’ll save, the planet we’ll preserve -- that is the kind of future our kids and our grandkids deserve. And it's within our grasp.
Climate change is just one of many issues where our security is linked to the rest of the world.
His final reference to climate change came while discussing international engagement, and "seeing our foreign assistance as a part of our national security":
When we lead nearly 200 nations to the most ambitious agreement in history to fight climate change, yes, that helps vulnerable countries, but it also protects our kids.
Climate, energy, and environmental issues thus featured prominently in the 2016 State of the Union speech.  Over the coming year, these themes -- domestic and international action on climate change, investment in renewable energy and distributed generation, transition away from oil and coal -- will likely continue to play out at the federal level.

Previewing climate and energy in 2016 State of the Union

Tuesday, January 12, 2016

President Obama is scheduled to deliver his final State of the Union address tonight. As in previous years, he is likely to address climate change, energy and environmental issues.  What will the 2016 State of the Union have to say about these topics?

We know from previous years' State of the Union speeches (2013, 2014, 2015) that energy, the environment, and climate change have played an increasing role in the Obama administration's priorities. While the administration released a "preview" video on Youtube for the 2016 address,  the brief clip doesn't include any substantive remarks about climate, energy, or the environment.

However, the Obama administration has been active on climate, energy and environmental issues, with key developments in the past year such as the adoption of the U.S. Environmental Protection Agency's Clean Power Plan regulations limiting power plant emissions of carbon dioxide and the denial of the Keystone XL pipeline's Presidential Permit application.  Indeed, President Obama has said that "no challenge poses a greater threat to our children, our planet, and future generations than climate change — and that no other country on Earth is better equipped to lead the world towards a solution."

Climate change, energy, and the environment are likely to be mentioned along with other administration priorities such as international relations, national security, gun violence, and the economy.  Indeed, the White House's State of the Union website features sections titled Economic Progress, Acting on Climate, Engagement in the World, Health Care Reform, and Social Progress and Equality.

Under the "Acting on Climate" heading, the administration website for this year's address notes the December 2015 Paris agreement on climate change, reduced domestic emissions, the largest investment in renewable energy in U.S. history, and associated job creation.  The website also provides a "Record on Climate Change", listing details of the administration's actions to address climate change.

President Obama's final State of the Union address to Congress will be streamed live at on January 12, 2016 at 9PM ET.

FERC dam license transfers, death and estates

What happens when an individual person dies holding a Federal Energy Regulatory Commission license for a hydroelectric project?  While their will may specify an heir for the dam and project works, the process of inheriting a licensed dam can involve both state estate law and a license transfer through FERC.

The Federal Energy Regulatory Commission licenses hydroelectric projects under Part I of the Federal Power Act.  The Commission's most recent list shows over 1,000 projects with licenses.  While most are held by corporate or public entities, about 25 licenses are held directly by named individuals.  Most of these projects licensed to individuals have relatively small authorized generating capacities, but once licensed their operation and transfer are governed by federal processes.

State law usually controls what happens to property owned by an individual upon his or her death.  Suppose the licensee's will provides that the licensed hydroelectric project is transferred to another person.   That provision may be valid as a matter of state law, but as a matter of federal law the license only transfers if the Commission approves the transfer.

Practically speaking, this can mean that the estate of the licensee needs to file an application to FERC for the transfer of the project license.  A recent application relating to the Pine Creek Hydroelectric Project in Montana illustrates this process.

The Commission initially issued a 50-year license for the Pine Creek project to Howard and Mildred Carter, on July 25, 1986, with a present authorized generating capacity of 373 kW.  After Howard Carter's death, Mildred Carter was the surviving licensee on the project.  After Mildred Carter's subsequent death, a Montana state court started the probate process through which the project would transfer to Mrs. Carter's son Allen.  In October 2015, the Carter estate applied to the FERC for transfer of the license to Allen.  The Commission issued a public notice of the application for transfer of license and solicited comments, motions to intervene, and protests, none of which were filed.

The Commission approved the Pine Creek project license transfer on January 8, 2016.  The order includes a finding that transfer of the license for this project is consistent with the Commission's regulations and is in the public interest.  Its approval of the transfer was contingent upon: (1) transfer of title of the properties under license, transfer of all project files including all dam safety related documents, and delivery of all license instruments to the inheriting licensee, which shall be subject to the terms and conditions of the license as though it were the original licensee; and (2) the heir acknowledging acceptance of the order and its terms and conditions by signing and returning an acceptance sheet.  The license transfer order required the new licensee to submit certified copies of all instruments of conveyance and the signed acceptance sheet within 60 days.

While direct inheritance of FERC-licensed hydroelectric projects is relatively rare, similar issues can arise when corporate entities holding FERC licenses dissolve or otherwise "die."  Depending on the specific facts, more common changes in ownership of an entity holding a FERC license may also require some activity to remain in compliance with federal law.

NH electric vehicle charging stations and utility status

Monday, January 11, 2016

As electric vehicles become increasingly popular, New Hampshire utility regulators have opened an investigation into the legal and regulatory issues implicated by the potential resale of electricity by electric vehicle charging stations.

On November 20, 2015, New Hampshire utility Liberty Utilities (Granite State Electric) Corp. d/b/a Liberty Utilities (Liberty) filed a tariff amendment to permit the resale of electricity for EVC stations, which the Public Utilities Commission docketed as Docket No. DE 15-489.  In a supporting technical statement, Liberty noted tariff language that currently prohibits the resale of electricity by most customers.  In Liberty's view, that prohibition forces owners and administrators of charging stations to charge in other manners, such as an hourly flat rate. 

On December 18, the Commission took two actions relating to the regulation of electric vehicle charging stations.  First, the Commission issued an Order of Notice announcing an investigation into the legal and regulatory issues implicated by the resale of electricity by electric vehicle charging stations.  The Commission made participation mandatory for the state's electric distribution utilities, and directed Commission staff to file a report by February 26, 2016, setting forth its conclusions and recommendations with respect to the sale of electricity to, and the resale of electricity by, EVC stations.  The Commission docketed this investigation as IR15-510.

Liberty pointed to "eighteen states that have adopted, through regulatory changes or legislation, exceptions for the resale of electricity for electric vehicle charging stations, including Maine and Massachusetts."  For example, a 2015 Maine law exempts an electric vehicle charging station provider from being considered a competitive electricity provider, and allows charging station providers to install an electrical submeter and to charge a submeter user only for kilowatt hours used,

Second, the Commission issued Order No. 25,852 in the Liberty docket on December 18, 2015, suspending the Liberty tariff amendment to permit Commission Staff (Staff) to complete the IR15-510 investigation.

Pursuant to the December 18 Order of Notice, legal memoranda are due from all electric distribution utilities and other interested persons on or before January 22, 2016.  Commission staff are scheduled to hold a stakeholder technical session on February 9, 2016. 

FERC enforcement report cites screenshots, keylogger

Thursday, January 7, 2016

The Federal Energy Regulatory Commission has issued an Order to Show Cause and Notice of Proposed Penalty against Coaltrain Energy, L.P. and six individuals relating to alleged fraudulent transactions in PJM Interconnection L.L.C.'s energy markets.  The Order, and a supporting Enforcement Staff Report, also includes allegations that Coaltrain made false and misleading statements and material omissions during the investigation.  Notably, the report describes FERC Enforcement staff's discovery of troves of documents allegedly covered up by the respondents, including keystroke logs and computer screenshots recorded by the company's software.  This e-discovery aspect gives FERC's Coaltrain enforcement case a unique character.

Fundamentally, the Coaltrain case presents FERC Enforcement staff's allegations that the respondents violated of the Commission’s Prohibition of Energy Market Manipulation, and that Coaltrain violated a Commission market behavior rule about accurate communications.  At issue is an alleged scheme involving trades from June 15 until September 2, 2010.  Traders allegedly engaged in a large volume of marginally profitable Up To Congestion (UTC) trades -- not to make money on those UTC trades, but with the intent to earn outsize payments from PJM's Marginal Loss Surplus Allocation (MLSA) program. FERC Enforcement staff's report describes its view of these trades as similar to those at issue in other recent enforcement cases, and different from normal arbitrage or "spread" trades.

The FERC Enforcement staff report in the Coaltrain case sheds light on another aspect of enforcement activity: how did Enforcement staff conduct its investigation of Coaltrain and the other respondents?  In this case, the company’s computer security monitoring software, called Spector 360, played a key role.  According to the report, Spector 360 "recorded every keystroke on employees’ computers (other than co-owners Peter Jones and Sheehan) and took screen shots of every employee monitor every twenty seconds all day long".

As staff noted in a footnote:
A large portion of the evidence in this matter is derived from the documents and other materials recorded by Spector 360. While the keystroke text data is not much different from ordinary documents, the screen shots taken by Spector 360 are very different, and create a visual record of what Respondents were working on, what they were looking for, how they conducted their analyses, and what they actually saw—as if standing over their shoulders while they work. This evidence will be reproduced as images taken from the screen shots.
Indeed, the Enforcement staff report includes a series of screenshots allegedly captured by Coaltrain's software.  According to the report, the evidence captured by Spector 360 shows how the respondents developed, implemented, and communicated about their scheme.

Not only does the FERC Enforcement staff report allege that this evidence exists, but moreover it alleges respondents made false and misleading statements about Spector 360 and the data it logged, including claims that they "forgot" about it.  According to the report, the Spector 360 data included material responsive to data requests issued as part of the investigation - but Coaltrain allegedly only provided it to Enforcement after a former employee told Enforcement that the Spector 360 data existed:
Enforcement sent several data requests to Coaltrain beginning in August 2010. In June 2012, Enforcement discovered from a former Coaltrain employee that Respondents had failed to produce an enormous set of documents that were highly relevant to the matters under investigation and responsive to Enforcement’s prior data requests. As it turned out, for nearly two years Respondents had failed to tell Enforcement that before, during, and after the summer of 2010, Coaltrain had deployed computer monitoring software, called Spector 360, that had recorded every keystroke (saved as text files) and made screenshots every twenty seconds of every monitor (saved as image files) on the work and home computers of every employee other than the co-owners, Peter Jones and Sheehan. Enforcement then asked Respondents to produce the missing materials. Respondents admitted that they still retained the data, but they at first refused to produce it by falsely denying that they could access the Spector 360 materials. Respondents belatedly produced the materials only after Enforcement arranged with the software manufacturer to give Respondents a new license at no cost. Once produced, the Spector 360 documents proved to be an enormous trove of responsive and relevant materials—about 10 gigabytes per employee during the summer of 2010.
FERC has docketed the case as IN16-4-000.  In its show cause order, the Commission directs Coaltrain and its co-owners to show cause why they should not be jointly and severally required to disgorge unjust profits of $4,121,894, and directs all Respondents to show cause why they should not be assessed civil penalties in the following amounts:
  • Coaltrain: $26,000,000
  • Peter Jones: $5,000,000
  • Shawn Sheehan: $5,000,000
  • Robert Jones: $1,000,000
  • Jeff Miller: $500,000
  • Jack Wells: $500,000
  • Adam Hughes: $250,000

FERC considers geomagnetic disturbance standards

Wednesday, January 6, 2016

U.S. energy regulators examining reliability standards for the electric transmission grid relating to geomagnetic disturbances have scheduled a technical conference for March 1, 2016.

Geomagnetic disturbance, or GMD, events occur during solar storms when the sun emits charged particles whose magnetic field interacts with that of the Earth.  GMDs can affect transformers, transmission lines, and other electric grid infrastructure.  As the Federal Energy Regulatory Commission noted in its Order No. 779, "there is a general consensus that GMD events can cause wide-spread blackouts due to voltage instability and subsequent voltage collapse, thus disrupting the reliable operation of the Bulk-Power System."

In 2013, the FERC issued Order No. 779 directing NERC to propose Reliability Standards that address the impact of geomagnetic disturbances (GMD) on the reliable operation of the Bulk - Power System.  In 2015, NERC made its proposal, which the FERC has proposed to largely accept.

But the case before FERC, docketed as RM15-11, remains ongoing.  Grid operators, utilities, trade groups, and others have filed comments or otherwise participated in the case.

The Commission has now scheduled a GMD technical conference on March 1, 2016, as a forum for "a structured dialogue on GMD-related topics."  Items specifically identified for discussion at this stage include what kind of GMD event should be used as the "benchmark" for planning purposes, vulnerability assessments, and monitoring of related parameters.

Mojave Water Agency conduit hydropower project qualifies

Monday, December 28, 2015

A California wholesale water provider has received a written determination from federal regulators that its proposed hydroelectric power project qualifies for easier regulatory treatment under federal law.  The project entails replacing a pressure reducing valve on an existing water supply pipeline with a hydropower turbine and generator, to create renewable electric energy.  Crucially, its qualification as a conduit hydropower project under a 2013 federal law enables its construction without a license under the Federal Power Act.

Under the Federal Power Act, most hydropower projects must be licensed by the Federal Energy Regulatory Commission.  But the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to ease the regulatory burden on certain projects described as "conduit hydropower" -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  The 2013 reform law exempted qualifying conduit hydropower facilities from needing licensure, and created an expedited process for soliciting public comment and determining whether the exemption applies.

This reform has led to a resurgence of interest in developing in-conduit hydroelectric projects.  For projects meeting the qualifying criteria, the FERC can act swiftly in issuing a determination that no licensure is required.  In some cases, this determination can come less than 60 days after an applicant files its notice of intent.

FERC's first conduit hydro docket in fiscal year 2016, CD16-1, illustrates this pace.  In that docket, the Mojave Water Agency was able to secure a written determination that the project it proposed meets the qualifying criteria under section 30(a) of the Federal Power Act, and thus is not required to be licensed under Part I of the FPA.

Among other operations, the Mojave Water Agency stores and distributes water in California's High Desert region.  An existing 48-inch pipeline conveys raw water sourced from the State Water Project to the Mojave River Basin for groundwater recharge.  Currently, pressure is reduced through a sleeve valve before discharging the SWP water to the Mojave River Basin by gravity flow.  But under the proposed Deep Creek Hydroelectric project, a hydroelectric turbine will perform the pressure reducing function while powering a generator capable of producing renewable electric energy.  According to the Mojave Water Agency, the hydroelectric station capacity will be 800 kW, with annual estimated power generation of 5,424 MWh.

On October 13, 2015, the MWA applied to the FERC for a determination that the Deep Creek project is a Qualifying Conduit Hydropower Facility, meeting the requirements of section 30(a) of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA).

On October 15, 2015, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria for a qualifying conduit hydropower facility, and thus was not required to be licensed under Part I of the FPA. The notice established a 45-day period for entities to contest whether the project met the criteria. No comments or interventions were filed in response to the notice.

As a result, on December 3 the FERC issued a letter constituting a written determination that the Deep Creek Hydroelectric Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA.

Other proposed conduit projects have benefited from this quick timeline and relatively streamlined process.  Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.

ISO-NE Winter Reliability Program 2015 by the numbers

Tuesday, December 22, 2015

The operator of New England's electric grid is running a special Winter Reliability Program to address fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints.  A December 2015 presentation by ISO New England, Inc.'s CEO provides initial cost and participation data on this winter's program.

More than 45% — about 13,650 MW—of the total generating capacity in New England uses natural gas as its primary fuel.  Out of this gas-fired capacity, ISO-NE's Winter Outlook has identified 4,220 MW of natural gas-fired generation at risk of not being able to get fuel when needed due to constraints on interstate natural gas pipelines.

As in 2013 and 2014, in 2015 ISO-NE again proposed a Winter Reliability Program to address concerns over reliability.  The 2015-2016 program includes 4 main components: oil, LNG, demand response, and dual-fuel commissioning.  According to a December 2015 presentation to the NEPOOL Participants Committee, program participation and expected cost exposure breaks down as follows:

Oil Program
  • 81 units submitted intent to provide 4.464 million barrels
  • Total eligible oil is anticipated to be 2.965 million barrels
  • Total oil program cost exposure is anticipated to be $38.25M (@$12.90/barrel

LNG Program
  • 8 units submitted intent to provide at least 1.42 million MMBTU
  • Total eligible LNG is 1.278 million MMBTU
  • Total LNG program cost exposure is anticipated to be $2.75M (@$2.15/MMBTU

Demand Response Program
  • 7 assets submitted an intent to participate; 6 accepted by ISO-NE, to provide at least 26.5 MW of interruption capability
  • Total DR program cost exposure is anticipated to be $132K

Dual-fuel Commissioning Program
  •  6 units submitted intent to commission Dual Fuel Capability
    • 4 units for 2014/15 (1,039 MW)
    • 2 units for 2015/16 (735 MW)
  • Total additional winter seasonal claimed capability represented: 1,774 MW

ISO-NE will release additional information on actual 2015/2016 Winter Reliability Program operations and costs over the winter period.

USDA REAP loan guarantee Maine funding available

Funding is available for energy projects at Maine's rural small businesses and agricultural producers through the USDA Rural Development agency's Rural Energy for America Program (REAP).  At stake is about $200 million in guaranteed loan funds available to finance renewable energy and energy efficiency projects in fiscal year 2016.

Since 2008, the USDA REAP program has provided grants and loan guarantees for renewable and energy efficiency projects at qualifying rural small businesses and agricultural producers.  Its loan program helps finance renewable energy systems and energy efficiency improvements.  Typical projects awarded funding in previous rounds include biomass fueled anaerobic digesters and biodiesel production, solar, wind, geothermal, efficient lighting conversions, motor upgrades, building envelope and HVAC improvements. 

REAP describes its loan guarantee program as lender-driven.  Usually, a qualifying farm or business will approach a lender to discuss financing a proposed project.  That lender then requests the USDA Rural Development loan guarantee, and if approved, makes and services the loan.  Guaranteed loan amounts can range from $5,000 to $25 million.  The guaranteed loan amount can cover up to 75% of the total eligible project cost, while 25% of project costs must come from other sources like business equity or other borrowed funds.

USDA Rural Development provides more information on its website about how to apply for a USDA REAP loan guarantee.  The Preti Flaherty team helps our clients understand how to benefit from REAP funding and other incentive programs for renewable energy and energy efficiency.  Contact Todd Griset to learn more.

FERC 2015 report on demand response, advanced metering

Monday, December 21, 2015

Staff of the Federal Energy Regulatory Commission have released their tenth annual report on demand response and advanced metering.  The FERC staff report, 2015 Assessment of Demand Response and Advanced Metering, provides an update on deployment of demand response and advanced metering.

Section 1252(e)(3) of Energy Policy Act of 2005 (EPAct 2005) directed the FERC to prepare and publish an annual report covering six sets of items:
  • saturation and penetration rate of advanced meters and communications technologies, devices and systems;
  • existing demand response programs and time-based rate programs;
  • the annual resource contribution of demand resources;
  • the potential for demand response as a quantifiable, reliable resource for regional planning purposes;
  • steps taken to ensure that, in regional transmission planning and operations, demand resources are provided equitable treatment as a quantifiable, reliable resource relative to the resource obligations of any load - serving entity, transmission provider, or transmitting party; and
  • regulatory barriers to improved customer participation in demand response, peak reduction and critical period pricing programs.
Previous reports have noted growth in the penetration of advanced metering and the value of demand response.  As in recent years, the 2015 FERC demand response report notes a continued increase in advanced meter penetration rates and the number of advanced meters in operation in the United States.

Based on 2013 data from the Energy Information Administration, the report suggests a 37.6 percent overall penetration rate.  It also shows a slightly higher percentage of residential customers have an advanced meter (37.8 percent) than do customers in the commercial (36.1 percent) or industrial (35.2 percent) customer classes.

At the same time, the FERC report shows a 4.9 percent drop in nationwide total potential peak reduction from retail demand response programs between 2012 and 2013, or a drop of 1,408 MW of demand response capability.  It also notes legal uncertainty over FERC’s final rule on demand response compensation in organized wholesale electric markets, Order No. 745, given that the U.S. Court of Appeals for the D.C. Circuit vacated and remanded that order in Electric Power Supply Association v. FERC, No. 11-1486 (D.C. Cir. May 23, 2014).  FERC's appeal of the EPSA v. FERC decision is now pending before the U.S. Supreme Court, with a final decision expected in early 2016.

Section 242 hydroelectric incentive program funding

Friday, December 18, 2015

For the first time, the U.S. Department of Energy has funding for its Section 242 hydroelectric incentive program.  The program, arising from Section 242 of the Energy Policy Act of 2005,  provides incentive payments for adding new turbines or other hydroelectric generating devices to existing sites. The Department is accepting applications for the incentive payments through February 1, 2016.

In 2005, as part of the Energy Policy Act of 2005, Congress created the Section 242 hydroelectric incentive program to support the expansion of hydropower energy development at existing dams and impoundments.  Section 242 establishes an incentive for qualified hydroelectric facilities, defined as "a turbine or other generating device owned or solely operated by a non-Federal entity which generates hydroelectric energy for sale and which is added to an existing dam or conduit."  The incentive is set at up to 1.8 cents per kilowatt-hour of net electric energy generated and sold by a qualified hydroelectric facility, indexed for inflation (about 2.3 cents per kilowatt-hour today) up to a maximum of $750,000 per year, for a specified 10-year period.

To get this money, an owner or operator must apply for the incentive payments.  An application for an incentive payment for electric energy generated and sold in a calendar year must be filed during the applications period defined by the Department of Energy in the Federal Register.  But according to the Energy Department's final guidance for the Section 242 program, "DOE will accept applications and make payments to qualified hydroelectric facilities in years when appropriations are available for this purpose."  Until recently, no such appropriations were available.

In Congressional appropriations for Federal fiscal year 2015, the Department of Energy received funds to support this hydroelectric incentive program for the first time. As shown in the conference report to the law that made appropriations for Fiscal Year 2015, Congress appropriated $3,960,000 for conventional hydropower under section 242 of EPAct 2005.

With funding now available, the Energy Department is only accepting applications from owners and authorized operators of qualified hydroelectric facilities for hydroelectricity generated and sold in calendar year 2014. Applications for this round of Section 242 funding are due by February 1, 2016.

FERC hydro dam relicensing, timing and options

Thursday, December 17, 2015

Under U.S. law, the Federal Energy Regulatory Commission has jurisdiction over most hydropower dams and projects.  The Federal Power Act directs the Commission to issue licenses for hydropower projects for a defined term of years, and provides the basis for the FERC hydro relicensing process.  The relicensing process can take years, and often must be started before a licensee has made final long-term plans for the project's fate.  For example, what if a FERC licensee is considering surrendering the license and removing the dam, at the same time that its existing license approaches expiration and a relicensing application is due?

A recent order by FERC staff under its delegated authority in City of River Falls, Wisconsin, P-10489-014, illustrates this dynamic.  The City of River Falls, Wisconsin, holds the license for the River Falls Project on the Kinnickinnic River, in Pierce County, Wisconsin.  When the license for the River Falls Project was issued, the Commission determined that a 30-year term was appropriate and in the public interest.  That current license expires on August 31, 2018.

Because the FERC hydropower relicensing process can take years -- or longer -- licensees who wish to retain licensure are required to start the planning, stakeholder, and application filing processes early.  In the River Falls case, a relicense application will be due by August 31, 2016.  To get the ball rolling, in 2013 the City filed a Notice of Intent (NOI) to relicense the project and Pre-Application Document (PAD) and elected the Commission’s Traditional Licensing Process (TLP).

Meanwhile, the City of River Falls is trying to evaluate the project's future.  The City is considering surrendering the license instead of continuing with relicensing, and to draft and adopt a Kinnickinnic River Corridor Planning Strategy to "reflect a single community vision for the river, with or without the hydroelectric project."

But the studies and deliberation required to evaluate dam relicensing, surrender, or alternatives take time.  Meanwhile, the clock ticks toward license expiration.  The City tried to buy 5 more years, by asking FERC to extend the termination date of its existing license, so that it expires on August 31, 2023.  As described by FERC:
The City states the additional time is needed so that it does not spend time and money relicensing the project only to determine through its Corridor Plan that the license should be surrendered and the project decommissioned. The City believes that a lengthy and expensive licensing process is the wrong process for making such a determination. The City explains that a decision about the future of the project would be made by the fall of 2017, and a notice of intent to relicense the project or a surrender application would be filed no later than August 31, 2018.
The City's request was supported by public commenters, mostly on the theory that an extension would allow time to explore license surrender and dam removal.

But as expressed in the order, the Commission saw "no reason why the City cannot evaluate both license surrender and relicensing in the remaining time it has to file a relicense application (due August 31, 2016). In fact, analysis of studies and feedback from agencies would help inform its decision of whether or not to continue to pursue the project."  In particular, the Commission did not view the simultaneous City's Corridor Plan process as "unique circumstances or circumstances beyond the City’s control that prevent it from making a determination by August 31, 2016... as to whether to relicense or to surrender the project."

The Commission also distinguished the River Falls case from precedent where it has extended other license terms, either to enable a licensee to amortize the cost of substantial improvements to project facilities or substantial new environmental measures, or to coordinate the license expiration date with the expiration dates of other licenses in the same river basin.

Ultimately, the Commission denied the City of River Falls, Wisconsin’s application to extend the license term for the River Falls Project from August 31, 2018, to August 31, 2023.  As noted in the Commission's order, the "City remains able to work on both a relicensing option and a surrender option while it develops its Corridor Plan should the City wish to do so."

The City has filed its Notice of Intent and Pre-Application Document, and has received Commission approval to use the Traditional Licensing Process.  Any relicense application will be due 2 years before the current license expires, or on August 31, 2016.  In the meantime, the City will presumably continue to explore its options, including license surrender and dam removal, or relicensing the project.

FERC hydropower and successive preliminary permits

Wednesday, December 16, 2015

U.S. federal regulators can give a preliminary permit to the developer of a proposed hydropower projects -- but won't give out a successive permit unless the developer demonstrates it acted diligently under its prior permit.

Developers of proposed hydropower projects in the U.S. can apply for a preliminary permit from the Federal Energy Regulatory Commission.  During its term -- up to three years, according to the Federal Power Act -- a preliminary permit for a hydropower project does not authorize construction, but gives the permittee first priority to apply for a license for the project.  This exclusivity allows the permittee to study the site, communicate with stakeholders, and develop the information necessary to support a license application.  It also gives the permittee something of a "reservation" for the site during its term.  In exchange, the permittee must submit periodic reports on the status of its outreach efforts and studies.

Sections 4(f) and 5 of the Federal Power Act authorize the Commission to issue preliminary permits to potential license applicants for a period of up to three years.  While the statute does not specify how many preliminary permits an applicant may receive for the same site, the Commission's policy is to grant a successive preliminary permit only if it concludes that the applicant has pursued the requirements of its prior preliminary permit in good faith and with due diligence.   The Commission has noted that each application for a successive preliminary permit is considered on a case-by-case basis, but has described "a minimum bar that a permittee must achieve to be diligent."

A recent FERC delegated staff order in Coralville Energy, LLC, Project No. 14431-001, illustrates this policy.  On November 2, 2015, Coralville Energy applied to the FERC for a preliminary permit for the Burlington Street Dam Hydroelectric Project, to be located at the existing Burlington Street Dam on the Iowa River, near Iowa City in Johnson County, Iowa. 

But this was not Coralville Energy's first application relating to the Burlington Street; it had received a preliminary permit three years earlier, on October 18, 2012.  According to the 2015 order, the record under that prior permit "shows that Coralville Energy did not pursue the requirements of its prior permit with due diligence for purposes of receiving a successive permit because it fails to demonstrate progress toward preparing a development application."

In particular, the 2015 order notes that semi-annual reporting under the 2012 preliminary permit noted a series of items: late reports filed subsequent to Commission staff’s letters warning Coralville Energy of probable cancellation for failure to file progress reports; reports that were too brief, vague, and "nearly identical"; no change to the study plan from that proposed in 2012, suggesting no progress made toward the preparation of a development application; and no information about conducting, reviewing, or coordinating environmental studies or the status of the permittee’s efforts to obtain permission to access and use land not owned by the permittee.

By contrast, the order describes Commission staff's view that the requisite diligence requires completion of certain steps towards preparing a development application, including "developing study plans, conducting studies in a timely fashion, consulting with  resource agencies, and developing the application in accordance with the Commission’s regulations."  Additionally, Commission staff have said that it "must be able to discern a pattern of progress toward the preparation of a development application from the content of a permittee’s filings."

On this basis, the 2015 order denied Coralville Energy’s application for a successive preliminary permit.  The order illustrates FERC hydropower staff's perspective on the level of diligence expected of the holder of a preliminary permit.  It also highlights the importance of substantive action in pursuit of a license or development application as well as timely and adequate semi-annual reporting by preliminary permittees.

Paris climate agreement walkthrough

Tuesday, December 15, 2015

On December 12, the Parties to the United Nations Framework Convention on Climate Change adopted Decision 1/CP.21, adopting the Paris Agreement under that convention. The Paris Agreement itself is 12 pages long, and includes a preamble and 29 articles.  Its details merit a close read, as parties spent countless hours negotiating every word and piece of punctuation in the document.  Some articles have many operative clauses and address topics like temperature change and greenhouse gas emissions, while other articles are more ministerial.  Billions of dollars, and maybe the fate of the world, rests on the terms of these legal documents and how they are implemented.

Here's a overview-level walkthrough of the Paris Agreement:

  • Preamble: recognizes climate change as a "common concern of humankind" and an "urgent threat" to which an "effective and progressive response" is necessary, that least developed countries and others may have specific needs, and interactions with other social values like food security, decent work and quality jobs, and "the importance for some of the concept of 'climate justice'".
  • Article 1 provides definitions for Convention, Conference of the Parties, and Party.
  • Article 2 defines the Agreement's aim as "to strengthen the global response to the threat of climate change, in the context of sustainable development and efforts to eradicate poverty," including a long-term temperature goal, a call for increased adaptation, and "making finance flows consistent with a pathway towards low greenhouse gas emissions and climate-resilient development."
  • Article 3 requires all parties "to undertake and communicate ambitious efforts as defined in Articles 4, 7, 8, 10, 11, and 13" as "nationally determined contributions to the global response to climate change."
  • Article 4 addresses the long-term temperature goal established in Article 2.  It requires each party to "prepare, communicate and maintain successive nationally determined contributions that it intends to achieve" and to pursue domestic mitigation measures.  Parties are expected to increase the level of ambition reflected in their nationally determined contributions over time.  Developed country parties are expected to take the lead, while supporting developing country parties and small island developing states.
  • Article 5 calls for conservation and enhancement of sinks and reservoirs of greenhouse gases, including forests.  
  • Article 6 recognizes that some parties may choose to pursue voluntary cooperation in implementing their nationally determined contributions.  It establishes a mechanism to promote and track "internationally transferred mitigation outcomes."  It also defines a framework to promote non-market approaches.
  • Article 7 establishes a global goal of enhancing adaptive capacity, strengthening resilience and reducing vulnerability to climate change.  It requires parties to engage in adaptation planning processes and actions.  It also requires periodic "adaptation communication" reporting to the secretariat.
  • Article 8 addresses averting, minimizing, and dealing with "loss and damage" associated with the adverse effects of climate change, "including extreme weather events and slow onset events."  It uses the Warsaw International Mechanism for Loss and Damage associated with Climate Change Impacts as its basis.
  • Article 9 calls for developed country parties to provide financial resources to assist developing country parties with respect to both mitigation and adaptation, and to take the lead in "mobilizing climate finance from a wide variety of sources, instruments, and channels."
  • Article 10 promotes technology development and transfer to "improve resilience to climate change and to reduce greenhouse gas emissions."
  • Article 11 calls for "capacity-building", to enhance the capacity and ability of developing country and vulnerable parties to take effective climate change action such as adaptation and mitigation.
  • Article 12 requires cooperation on "climate change education, training, public awareness, public participation and public access to information."
  • Article 13 creates an "enhanced transparency framework for action and support" to build trust and confidence while allowing flexible and effective implementation.  It requires each party to regularly provide a "national inventory report of anthropogenic emissions by sources and removals by sinks of greenhouse gases," and information on how it has provided financial, technology transfer and capacity-building support to other countries.
  • Article 14 requires a "global stocktake" -- that the parties periodically "take stock of the implementation of this Agreement to assess the collective progress towards achieving the purpose of this Agreement and its long-term goals."  Article 14 provides that the Conference of the Parties shall undertake its first global stocktake in 2023 and every five years thereafter unless the Conference otherwise decides.
  • Article 15 establishes an expert-based committee as "a mechanism to facilitate implementation of and promote compliance with" the Paris Agreement.
  • Article 16 provides procedures for aligning future meetings of parties to the Paris Agreement with the meetings of the Conference of the Parties.
  • Articles 17, 18, and 19 provide procedures for the Convention secretariat, Subsidiary Body for Scientific and Technological Advice and Subsidiary Body for Implementation established by the Convention to also apply to the Paris Agreement.
  • Article 20 provides processes for signature, ratification, acceptance, approval and accession of the Paris Agreement.
  • Article 21 provides that the Paris Agreement "shall enter into force on the thirtieth day after the date on which at least 55 Parties to the Convention accounting in total for at least an estimated 55 percent of the total global greenhouse gas emissions have deposited their instruments of ratification, acceptance, approval or accession."
  • Articles 22 and 23 provide processes for adopting any amendments or annexes to the Paris Agreement.
  • Article 24 governs dispute resolution.
  • Article 25 provides that each party shall have one vote, and establishes a process for "regional economic integration organizations" to vote as a bloc.
  • Article 26 provides that the Secretary-General of the United Nations shall be the Depositary of the Paris Agreement.
  • Article 27 prohibits any reservations being made to the Agreement.
  • Article 28 provides a process for a party to withdraw from the Paris Agreement.
  • Article 29 governs the original of the Paris Agreement.
The final language of the Paris Agreement's 29 articles, and Decision 1/CP.21 adopting the Paris Agreement, were each adopted by consensus by all of the 195 member states and the European Union participating in the COP21 summit.  Decision 1/CP.21 and the Paris Agreement will play important roles going forward as the world tackles climate change.  Their language will shape business, government, society, and the environment. 

Guide to the Paris climate agreement decision

Representatives from 195 countries signed a climate agreement on Saturday at the COP21 United Nations climate summit in Paris.  The resulting Paris climate agreement calls upon both developed and developing nations to reduce emissions of greenhouse gases, and establishes a framework for reviewing progress every five years.  This post examines the formal decision to adopt the Paris Agreement taken by the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC).

Under the procedural rules governing the Conference of the Parties, the parties adopted "decision 1/CP.21", the draft of which was proposed by the President of the Conference of the Parties.  Decision 1/CP.21 formally adopts the Paris Agreement -- contained in an annex to the decision -- and creates processes supporting its implementation.

Decision 1/CP.21 emerges from the parliamentary procedures used by the U.N. and the Conference of the Parties.  Written in formal language, the draft decision includes a preamble and six active sections:
  • The preamble recites the agreed-upon facts motivating the Paris agreement, such as, "climate change represents an urgent and potentially irreversible threat to human societies and the planet and thus requires the widest possible cooperation by all countries."
  • Section I, "Adoption," formally adopts the Paris Agreement under the United Nations Framework Convention on Climate Change as contained in the annex, and establish the Ad Hoc Working Group on the Paris Agreement to facilitate its implementation.
  • Section II, "Intended Nationally Determined Contributions," invites participating countries to submit "intended nationally determined contributions" towards achieving the objective of the Convention "as soon as possible and well in advance of the twenty-second session of the Conference of the Parties (November 2016)."
  • Section III, "Decisions to Give Effect to the Agreement," includes sections covering mitigation, adaptation, loss and damage, finance, technology development and transfer, capacity-building, transparency of action and support, global stocktake, facilitating implementation and compliance.
  • Section IV, "Enhanced Action prior to 2020," calls for "the highest possible mitigation efforts in the pre-2020 period," such as "the provision of urgent and adequate finance, technology and capacity-building support by developed country Parties in order to enhance the level of ambition of pre-2020 action by Parties," with a goal of jointly providing USD 100 billion annually by 2020 for mitigation and adaptation.
  • Section V, "Non-Party Stakeholders," welcomes interest, participation, and parallel efforts by non-Party Stakeholders, such as "civil society, the private sector, financial institutions, cities and other subnational authorities."
  • Section VI, "Administrative and Budgetary Matters," notes potential limits on available financial resources, and urges that parties voluntarily make additional resources available.
Through this COP21 decision, the Conference of Parties adopted the Paris Agreement itself.   In a companion post, I provide a walkthrough of the terms of the Paris Agreement itself.