DOE report finds Solyndra gave "false and misleading" info

Tuesday, September 1, 2015

The Department of Energy's Office of Inspector General has released a special report finding that failed solar panel maker Solyndra, Inc. provided the Department with inaccurate and misleading information during the application process for a $535 million loan guarantee.  The report summarizes the results of a 4-year investigation into what went wrong with the Solyndra matter, and what lessons the Department can learn as it proceeds to exercise its authority to grant an additional $40 billion in loan guarantees.

In 2005, Congress established a federal loan guarantee program for eligible energy projects that employed innovative technologies. Title XVII of the Energy Policy Act of 2005 authorized the Secretary of Energy to make loan guarantees for a variety of types of projects, including those that “avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases; and employ new or significantly improved technologies as compared to commercial technologies in service in the United States at the time the guarantee is issued.”

The Department of Energy loan guarantee program was expanded by the American Recovery and Reinvestment Act of 2009, which added billions of dollars of new authority to support renewable energy, electric transmission, and advanced biofuels projects.  The Department's Loan ProgramsOffice has supported a portfolio of more than $30 billion in loans, loan guarantees, and commitments covering more than 30 projects across the United States.

The Department made its first award under this program in September 2009, approving a $535 million loan guarantee to a company called Solyndra, Inc.  Solyndra said it would build a solar photovoltaic equipment manufacturing facility in Fremont, California.  The Energy Department disbursed over $500 million to Solyndra through the program.  But just two years later, Solyndra showed signs of failure, as it ultimately stopped operations and manufacturing, let 1,100 employees go, and filed for bankruptcy.  U.S taxpayers lost over $500 million.

The Solyndra matter drew significant public attention, with even the Department calling it an "ordeal" and many labeling it a scandal.  What went wrong?  Should the government have guaranteed Solyndra's loans?  Was the loan guarantee program flawed?  Or was it acceptable bad luck that the first awardee failed?

Since 2011, the Department of Energy's Office of Inspector General has investigated the Solyndra matter.  Its special report released August 24, 2015, describes the Inspector General's findings:
Our investigation confirmed that during the loan guarantee application process and while drawing down loan proceeds, Solyndra provided the Department with statements, assertions , and certifications that were inaccurate and misleading , misrepresented known facts , and, in some instances, omitted information that was highly relevant to key decisions in the process to award and execute the $535 million loan guarantee. In our view, the investigative record suggests that the actions of certain Solyndra officials were, at best, reckless and irresponsible or, at worst, an orchestrated effort to knowingly and intentionally deceive and mislead the Department.
In particular, the report identified "notable misrepresentations and omissions made to the Department by Solyndra" relating to Solyndra's sales contract commitments and ability to command a premium market price for its panels.  The report suggests this false and misleading information led the Department to approve the loan guarantee, when it might not have done so with the right information.  The report found that Solyndra failed to meet contractual obligations from the loan guarantee documents relating to truth and full disclosure.

The Inspector General's special report also found that the Energy Department's due diligence efforts were "less than fully effective", with missed opportunities to detect and resolve indicators that portions of the data provided by Solyndra were unreliable.  Nevertheless, the report concludes that ultimate blame should fall on the company: "the actions of the Solyndra officials were at the heart of this matter, and they effectively undermined the Department’s efforts to manage the loan guarantee process. In so doing, they placed more than $500 million in U.S. taxpayers’ funds in jeopardy."

The Department of Energy continues to offer loan guarantees for a variety of technologies and projects.  The report suggests that the Department strengthen its due diligence process, and reemphasize to loan applicants their absolute obligation to be truthful, complete, timely and transparent.

Navy signs solar energy deal

Thursday, August 27, 2015

The U.S. Department of the Navy has announced an agreement for the development of a 210 megawatt (DC) solar project to supply electricity to Navy and Marine Corps facilities in California.  The Navy described the deal as the largest purchase of renewable energy by a federal entity to date.

Solar photovoltaic panels in Utah - much smaller project than the Navy project.
The Navy has expressed interest in renewable and alternative energy for some time, buying biofuels and renewable electricity.  According to the website for Deputy Assistant Secretary of the Navy - Energy, Joseph Bryan:
The Navy's energy strategy takes the "long view" necessary to keep our Navy and our nation strong. Bottom line: incorporating energy initiatives now will allow us to more effectively carry out our mission in the future.
In 2009, Congress mandated that 25 percent of the energy used in Department of Defense facilities come from renewable sources by 2025.  Secretary of the Navy Ray Mabus then set an accelerated goal for his branch of the military: 1 gigawatt of renewable energy procurement by the end of 2015.  In the Navy's view, resources like solar power can help diversify its shore energy portfolio and provide long-term cost stability, which ultimately contributes to the Navy's overall energy security priorities.

In furtherance of this goal, last year the Western Area Power Administration issued a request for proposals for renewable energy projects to supply power to Navy facilities in California.  Through a competitive process, Sempra U.S. Gas & Power LLC was selected to develop the Mesquite 3 Solar project.  Sempra is a subsidiary of San Diego-based Sempra Energy, a major energy services holding company. It has developed a variety of solar and wind energy generation projects, including the existing Mesquite 1 Solar project about 60 miles west of Phoenix, Arizona.

The Navy announced that it had signed the agreement on August 20, at a ceremony co-hosted by Western Area Power Administration and Sempra.  Under the Navy deal, Sempra will develop the Mesquite 3 project as an expansion of the existing Mesquite site.  Mesquite 3 will feature over 650,000 photovoltaic panels on ground-mounted, horizontal single-axis trackers.  Construction is scheduled to begin in August, with completion expected by the end of 2016.  While pricing terms have not been disclosed, the Navy reports that it will save at least $90 million over the life of the project.

Will other units of federal government follow the Navy's model in contracting for renewable energy in this manner?  How will solar project business structures change if federal entities start playing a larger role as buyers?

Cross-border infrastructure and presidential permits

Wednesday, August 26, 2015

A recent report casts doubt on whether proposed federal legislation would actually accelerate decisions on the siting of cross-border energy infrastructure.

Cross-border pipelines and electric transmission lines play an important role in the North American energy industry.  Under U.S. law, cross-border energy infrastructure projects require a presidential permit and a finding of consistency with the national interest.  Executive orders give the State Department jurisdiction over cross-border oil pipelines, the Department of Energy jurisdiction over electric transmission lines, and the Federal Energy Regulatory Commission jurisdiction over natural gas pipelines. 

Recent projects like the Keystone XL pipeline have focused attention on the presidential permit process, as that project's presidential permit application has remained pending for years.  Some have raised questions about the scope of agency review and perceived differences in the approaches taken by the State Department, Energy Department, and FERC.

As a result, several members of Congress have proposed legislation designed to accelerate the permitting process.  These bills include:

These bills take various approaches, including limiting agency jurisdiction over cross-border energy infrastructure or the scope of agency review, or setting strict deadlines for agency action following completion of environmental review.

Could federal legislation like this speed up the process for reviewing proposed cross-border pipeline and electric transmission projects?  A recent report by the Congressional Research Service suggests that overall timelines for project review are driven by the scope of the environmental review process, not by delays following that environmental review or agency idiosyncrasies.

In particular, the report found that agency review is "driven largely by the National Environmental Policy Act (NEPA)", which requires federal agencies to consider the environmental impacts before acting.  Moreover, the report notes that the same NEPA requirements apply to all three:
Faced with Presidential Permit applications for energy projects of similar physical scope, the agencies appear to perform NEPA reviews of similar proportion. Very short, smaller projects are generally reviewed more narrowly and quickly, whereas multi-state projects of large capacity are subject to more expansive environmental review and tend to face much greater public scrutiny and comment—regardless of which agency has jurisdiction. 
The report also found that NEPA review is the key driver of overall permitting decision timelines:
As long as agencies apply NEPA to Presidential Permitting decisions, changes to the delineation of, or jurisdiction over, the border-crossing portion of large projects for permitting purposes may not change the scope of project environmental review. The imposition of decision deadlines on the permitting agencies after NEPA review is complete, either for national interest or public interest determination, could provide greater process certainty to stakeholders. However, the overall project review would still be contingent on the completion of NEPA review. Thus, the effects of legislative proposals to change cross-border infrastructure permitting on the review or approval of future border crossing energy infrastructure projects are open to debate. 
It's unclear how the Congressional Research Service report will affect pending legislation.  Likely more influential may be any final action by the State Department on the Keystone XL project's application for a presidential permit.  Nevertheless, interest in cross-border energy trade will likely continue to grow.

Northern Pass proposes new transmission plan

Monday, August 24, 2015

The developer of a proposed $1.4 billion electric transmission line connecting Quebec to New Hampshire has released a revised route for the project, following public opposition to earlier plans.  The new vision for the Northern Pass project would bury more of the line underground and reduce the project's overall capacity to haul power.  Will this version of the Northern Pass gain more traction?

First proposed in 2009, the Northern Pass would be a 192-mile high-voltage direct current (HVDC) transmission line.  It would bring up to 1,000 megawatts of power from Canadian power plants into New England, running from the Canadian border to a proposed converter terminal in Franklin, New Hampshire.  From there, a new alternating current (AC) transmission line would deliver the energy to New England’s electric grid at an existing substation in Deerfield, New Hampshire. 

Since it was first proposed, the Northern Pass route has drawn criticism; the project was delayed, and despite revisions to the route public opposition remained.  Throughout the process, many comments have focused on local siting impacts, like the effect of above-ground transmission lines and poles through Franconia Notch State Park, the White Mountain National Forest, and the Appalachian Trail.  Eversource proposed running 8 miles of cable underground to reduce these impacts, but argued that undergrounding more would make the project too expensive.

But the forces motivating the Northern Pass project and other proposed HVDC lines from Canada remain strong: demand in New England and New York for electricity, and in particular for hydropower and other renewable electricity imported from Canada.

On August 18, project lead Eversource Energy announced changes to the route and scope of the project.  While the previous vision included 8 miles of underground cable to avoid visual impacts, the so-called "Forward New Hampshire Plan" now includes 60 miles of underground cable. Eversource described its revised route as striking "a balance between New Hampshire and our region’s need for a reliable new energy source and avoiding potential impacts to the state’s scenic landscapes."  At the same time, the revised proposal reduces the line's capacity from 1,200 megawatts to 1,000 megawatts, ostensibly to hold total costs at the previously estimated $1.4 billion.  The plan now includes $200 million to establish the "Forward NH Fund", a pool of money designed to support clean energy innovations, economic development, community investment, and tourism.

The Northern Pass project now faces public hearings.  Eversource is expected to file an application for site review with the New Hampshire Site Evaluation Committee in mid-October.

Block Island offshore wind celebrated, challenged

Thursday, August 20, 2015

U.S. and Rhode Island officials recently celebrated the start of construction on the Block Island Wind Farm, which is on track to be the first commercial offshore wind farm in the U.S.  The five-turbine, 30-megawatt project under development by Deepwater Wind is scheduled to come online in 2016; turbine foundation construction and other "steel in the water" activities are underway.  As a pioneer in U.S. offshore wind development, the Block Island project has survived years of permitting uncertainty and repeated legal challenges by project opponents.  But another such lawsuit was filed this week in federal court.  What does the future hold for the Block Island Wind Farm?

Project developer Deepwater Wind is owned principally by an entity of the D.E. Shaw group.  Its Block Island project is currently under construction in Rhode Island state waters about three nautical miles southeast of Block Island.  The project will feed power directly to consumers on Block Island, but also includes a 25-mile bi-directional submerged transmission cable between Block Island and the mainland. The project's finances rest in part on a power purchase agreement through which Deepwater Wind will sell power to utility National Grid.

That power purchase agreement, or PPA, has been the subject of several legal challenges.  Those challenges often cite the deal's cost: pricing for the Block Island power starts as high as 24.4 cents per kilowatt-hour, and escalates 3.5 percent annually.  These prices are more than double the typical Rhode Island energy price, for an estimated $497 million in above-market costs over the 20-year deal.

In 2009 and early 2010, the Rhode Island Public Utilities Commission rejected proposals by Deepwater Wind and National Grid, largely over cost.  The parties then returned with a revised proposal.  In 2010, TransCanada Power Marketing Ltd. unsuccessfully argued that the Rhode Island commission shouldn't consider that proposal due to constitutional infirmities in the Rhode Island law favoring renewable power contracts with in-state projects.  On August 16, 2010, the Commission issued its order approving the PPA.  After that order was appealed to the state Supreme Court, the Supreme Court issued a written opinion upholding the Commission's Order on July 1, 2011.  In 2012 and in 2015, project opponents petitioned the Federal Energy Regulatory Commission to invalidate the Rhode Island commission's action, which FERC declined to do.  Through all this, the project moved forward and ultimately began local construction earlier this year.

But the project is not yet completely out of stormy seas.  On August 14, 2015, plaintiffs with a history of engagement in some of these earlier challenges filed a lawsuit in U.S. District Court in Rhode Island.  As in previous challenges, this complaint argues that the Rhode Island Public Utilities Commission violated federal laws in approving the Block Island deal because only the Federal Energy Regulatory Commission may regulate wholesale electricity sales.  While it is possible that this case could be swiftly dismissed, if it lingers it could add uncertainty to the project until its resolution.  Last year a federal court invalidated a FERC ruling on the grounds that it impermissibly tread on state rights to set retail electricity rates.  That case, Electric Power Supply Association v. Federal Energy Regulatory Commission, has been appealed to the U.S. Supreme Court.

With construction underway, the Block Island project now has significant inertia behind it.  What impact will the recently filed lawsuit have?  Will it affect Deepwater Wind's position as "first in the water" in the race for U.S. commercial offshore wind development?

EPA proposes methane rules for oil and gas

Wednesday, August 19, 2015

The U.S. Environmental Protection Agency has proposed a suite of new and modified rules affecting the oil and natural gas industry.  Collectively, the proposed rules released on August 18 are designed to reduce methane emissions from oil and natural-gas drilling activities.

As the world tackles climate change and greenhouse gas emissions, methane plays a dual role.  As the key constituent of natural gas, methane offers society an abundant and efficient fuel that can displace reliance on costlier and more carbon-polluting fuels like coal and oil.  At the same time, methane in the atmosphere can act as a greenhouse gas itself, with a global warming potential more than 25 times greater than that of carbon dioxide.  According to EPA, methane is the second most prevalent greenhouse gas emitted in the United States from human activities, and nearly 30 percent of those emissions come from oil production and the production, transmission and distribution of natural gas.  At the same time, U.S. production of oil and natural gas has increased, giving the sector important economic and domestic security impacts.

To address this dynamic, yesterday EPA proposed a series of rules affecting the oil and natural gas sector.  EPA has described the new rules as a "key component" of the Obama administration's Climate Action Plan.  They follow a January announcement of a new goal to cut methane emissions from the oil and gas sector by 40 to 45 percent of 2012 levels by 2025.  Under the administration's view, a key tool supporting that goal is the implementation of standards for methane and volatile organic compound (VOC) emissions from new and modified oil and gas production sources, and natural gas processing and transmission sources.

The rules EPA proposed yesterday include such standards, along with supporting materials.  EPA has described its collective proposal as "a suite of commonsense requirements that together will help combat climate change, reduce air pollution that harms public health, and provide greater certainty about Clean Air Act permitting requirements for the oil and natural gas industry."

EPA's proposed package of rules includes:

According to EPA, the proposed rule will reduce methane emissions by between 340,000 and 400,000 short tons in 2025,  on top of reductions of 170,000 to 180,000 tons of other VOCs and 1,900 to 2,500 tons of hazardous air pollutants.  But industry trade group American Petroleum Institute has called additional regulation "unnecessary for reducing emissions."  Debate over EPA's proposal is likely to be vigorous, before EPA as it considers its proposed rulemaking, as well as before Congress and possibly even federal courts, before the dust settles.

EPA will take public comment on the proposals for 60 days after they are published in the Federal Register.  According to the January announcement, the administration expects the final rule will follow in 2016.  This action on oil and natural gas production follows closely on the heels of EPA's adoption of the Clean Power Plan rules, regulating carbon emissions associated with the electric power industry.

Resources on Clean Power Plan

Tuesday, August 4, 2015

Yesterday President Obama announced his administration's "Clean Power Plan," the U.S. Environmental Protection Agency's new regulations limiting power plant carbon emissions under Section 111(d) of the Clean Air Act.

EPA's final Clean Power Plan rule establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas  emissions from existing fossil fuel-fired electric generating units. 

Here are some quick resources I've compiled as a guide to the Clean Power Plan and its release:

US Clean Power Plan adopted

Monday, August 3, 2015

President Obama will formally unveil the Clean Power Plan today, a set of regulations by the U.S. Environmental Protection Agency (EPA) to reduce carbon emissions associated with the electric power industry.  A blog post by EPA Administrator Gina McCarthy emphasizes the Clean Power Plan's protection of health and the environment, states' rights to choose their own implementation paths, reduction of future energy costs, and leadership on climate issues.  But some politicians, utilities and states have expressed concern about the regulations' impact, and could launch legal challenges -- or states might refuse to comply.  What's in store for the Clean Power Plan?

It has been just over a year since EPA first released its draft Clean Power Plan in June 2014.  These regulations under Section 111(d) of the Clean Air Act are designed to reduce the carbon intensity of the U.S. electric power sector -- essentially, how many pounds of carbon are emitted per megawatt-hour of electric energy produced.  Under the draft Clean Power Plan, EPA sets carbon intensity limits for each state, collectively designed to reduce carbon emissions by 30% below 2005 levels.  Each state then designs its own compliance plan using any combination of "building blocks": types of measures like improving the efficiency of fossil fuel power plants, switching out coal- and oil-fired power plants in favor of natural gas, and increasing low- and zero-carbon generation.

While the final Clean Power Plan's basic structure remains much the same, EPA has made some modifications in reaction to concerns about the greenhouse gas regulations' costs and impacts to grid reliability.

Changes from the 2014 draft include:
  • Two extra years (until 2022) for states to meet their targets, and greater flexibility for states to form regional pacts to facilitate emissions-cutting projects across state lines, such as the Regional Greenhouse Gas Initiative.
  • A new “safety valve” feature, to let states appeal for extensions and other relief if complying with the regulations causes disruptions to power supply.
  • Increased social justice incentives for utilities to construct renewable energy projects in poorer neighborhoods, reducing pollution-related illness and eventually lowering electricity rates.
  • Energy efficiency is still encouraged, but has been eliminated as one of the rule’s "building blocks” for states to use in building their own carbon-reduction plans.
How will the Clean Power Plan story continue to play out?  Will it be challenged in court?  Will states comply?  What impacts will it have on the U.S. electric power industry?

Regulators release updated energy primer

Friday, July 31, 2015

The Federal Energy Regulatory Commission has released an updated version of its "resource manual",  Energy Primer: A Handbook of Energy Market Basics.

The FERC is an independent federal agency that regulates a variety of aspects of the U.S. energy industry, including the interstate transmission of electricity, natural gas, and oil, proposals to build liquefied natural gas (LNG) terminals and interstate natural gas pipelines, and hydropower projects, as well as engaging in strategic planning.

FERC's Office of Enforcement is charged with encouraging compliance with the Commission’s statutes, rules, and orders.  Within the enforcement office, the Division of Energy Market Oversight is responsible for monitoring and overseeing the nation’s wholesale natural gas and electric power markets.

In 2012, the Division of Energy Market Oversight (or DEMO) issued the first edition of its Energy Primer.  This week, DEMO issued an updated 2015 version of the Energy Primer.  As with the previous edition, the 2015 Energy Primer gives the public a broad overview of the physical wholesale markets for natural gas and electricity and energy-related financial markets.  As FERC has noted, the revised edition reflects some of the changes that have occurred in the industry since 2012, including the growth in natural gas supplies and the expansion of organized electric markets under Independent System Operators (ISO) and Regional Transmission Organizations (RTO).

The 2015 FERC Energy Primer offers a useful introduction to the U.S. energy industry as it is regulated by FERC.  As with the 2012 version, FERC staff states that the 2015 edition is intended to be used as either a text or a reference guide.  FERC's website also notes that the Energy Primer is a product of FERC staff and does not reflect the views of the Commission or any individual Commissioner.  Nevertheless it may offer careful readers insight into how Commission staff view the markets' continuing evolution.

U.S. renewable energy share highest since 1930s

Tuesday, July 21, 2015

In 2014, about 9.8% of the total energy consumed in the U.S. came from renewable energy sources, according to the U.S. Energy Information Administration.  This represents the highest share of total domestic energy supply coming from renewable resources since the 1930s.

Prior to the growth of production and distribution networks for petroleum and other fossil fuels in the early 20th century, many homes used wood for heating as did industry.  This reliance on renewable biomass historically satisfied a significant portion of the total domestic energy demand.  But technological advances and the birth of the electric power industry led to greater use of other fuels.  As a result, the EIA reports that renewable resources' share of total domestic energy supply peaked in the 1930s, then declined.

But recent growth in U.S. renewable energy use has brought the country's energy mix back to nearly 10% renewable.  Indeed, from 2001 to 2014, renewable energy use grew an average of 5% per year, largely through increased use of wind, solar, and biofuels:
  • Wind energy grew from 70 trillion Btu in 2001 to more than 1,700 trillion Btu in 2014.
  • Solar energy (solar thermal and photovoltaic) grew from 64 trillion Btu to 427 trillion Btu.
  • The use of biomass for the production of biofuels grew from 253 trillion Btu to 2,068 trillion Btu.
According to EIA, inn 2014, slightly more than half of all renewable energy was used to generate electricity.  Renewable energy accounted for 13% of energy consumed within the electric power sector, the highest renewable use attributable to any sector.

Maine explores non-transmission alternatives coordinator

Thursday, July 2, 2015

Should Maine designate an entity to coordinate the development of lower-cost alternatives to new electric transmission lines?  The Maine Public Utilities Commission has opened an inquiry to obtain comments on the role of a non-transmission alternative (NTA) coordinator and the parameters for procuring the services of an NTA coordinator.

Modern society counts on electric utilities and power plants to supply consumers with electricity.  As consumer needs and plant economics change over time, utilities have traditionally looked to new infrastructure like transmission lines to meet new needs.  But in some cases, transmission development may not be the cheapest or best way to meet consumer needs; rather, "non-transmission alternatives" such as distributed generation, energy efficiency or microgrids may be able to achieve the same ends for a lower total cost.

Grid modernization -- and the tools needed to manage the process efficiently -- can be controversial.  By order dated May 11, 2015, the Maine Public Utilities Commission declined to designate a "Smart Grid Coordinator" to provide a broad array of services to the state, on the grounds that that the record before it did not support a finding that designate a coordinator to provide all these services was in the public interest.

But the Commission indicated interest in designating someone to provide the services of marketing, implementing, and possibly operating non-transmission alternatives.  To that end, the Commission found "there is the potential for benefits from an entity that has the relevant expertise and a commercial interest in the successful development and implementation of NTAs" -- provided that the entity can deliver its services in a way that provides value to ratepayers.

By a June 30 Notice of Inquiry, the Commission initiated the next phase of its exploration of designating an NTA coordinator.  The Commission requested comment on issues it had previously identified in its May 11 order as requiring further factual development to enable the Commission to determine whether it is in the public interest to designate an NTA coordinator:
  1. What duties should be included in the scope of services offered by an NTA coordinator?
  2. Should T&D utilities be allowed to bid on an NTA RFP and if so should such services be provided through an affiliate? 
  3. If an RFP were seeking proposals for having a non-utility entity operate an NTA in a manner consistent with reliability and cyber security standards, how would the incremental costs to operate the NTA be determined?
  4. What type of pricing structures should be considered in developing the RFP?
  5. What factors should be considered in bid evaluation?
  6. What should be the term of the NTA coordinator contract?
  7. What entities should be the counterparties to the contract?
  8. What enforcement mechanisms should be included in the contract?
  9. What type/amount of financial security should be required?
The Commission also invited comment on any other issues relevant to its consideration of designating an NTA coordinator.  The Commission requests that comments be filed by July 21, 2015.  After comments are received, Commission staff will schedule a meeting to discuss the comments and discuss next steps in the development of a request for proposals.

Supreme Court rules on EPA power plant regulations

Wednesday, July 1, 2015

The Supreme Court of the United States has ruled that the U.S. Environmental Protection Agency acted unreasonably in developing new regulations on hazardous air emissions from power plants without considering the cost impact of those regulations.  This ruling reinjects uncertainty into EPA's "Mercury and Air Toxics Standards" and other efforts to regulate power plant emissions under the Clean Air Act.

The federal Clean Air Act was designed to improve environmental quality and human health, among other goals.  It broadly allows federal regulation of air emissions of pollutants of various types and from various sources.

Because certain specific provisions in the Clean Air Act applied specifically to power plants, Congress placed a special restriction on EPA's regulation of power plant emissions under Section 7412(n)(1)(A) of the Clean Air Act.  That provision allows EPA to regulate emissions of hazardous air pollutants from power plants under Section 7412 only if it “finds such regulation is appropriate and necessary.”  In 2000, after a study, EPA concluded that regulating power plants under Section 7412 was "appropriate and necessary."  EPA reaffirmed this finding in 2012, and promulgated standards for emissions from power plants.

Along with those standards, EPA issued a “Regulatory Impact Analysis” estimating that the regulation would force power plants to bear costs of $9.6 billion per year.  That analysis also found that while benefits were hard to fully quantify, estimated benefits were worth $4 to $6 million per year.  Based on this analysis, compliance costs to power plants were thus between 1,600 and 2,400 times as great as the quantifiable benefits from reduced emissions of hazardous air pollutants.  At the same time, EPA argued that it did not have to consider costs in establishing its standards.

Following the issuance of these standards, 23 states sought review of EPA’s rule in the D. C. Circuit Court of Appeals in a series of cases which were later consolidated.  The D.C. Circuit upheld EPA's refusal to consider costs in its decision to regulate, at which point petitioners appealed to the Supreme Court. As my partner Jeff Talbert explains, in a 5-4 decision issued June 29, the Supreme Court held that EPA interpreted §7412(n)(1)(A) unreasonably when it deemed cost irrelevant to the decision to regulate power plants.

So what does the Supreme Court's ruling mean for U.S. power plants?  Uncertainty -- but not necessarily freedom from regulation.  The Supreme Court remanded the case back to the D.C. Circuit for further consideration.  The D.C. Circuit could uphold the rule again (on new grounds, compliant with the Supreme Court's decision) -- or it could invalidate the rule based on the Supreme Court ruling.  If that happens, EPA will likely have to resume the process of developing new regulations for hazardous air emissions from power plants under Section 7412.

New York's 2015 Energy Plan

Tuesday, June 30, 2015

The state of New York has released a sweeping plan for its energy future, featuring strengthened commitments to clean energy over the next four decades.  The 2015 New York State Energy Plan includes reductions in greenhouse gas emissions, increased generation of renewable energy, and improved energy efficiency.

Article 6 of New York's energy law requires the state's energy planning board to develop period state energy plans.  The state released its two-volume 2015 report on June 25, presenting "a comprehensive strategy to create economic opportunities" in New York based on Governor Andrew Cuomo's previously-announced "Reforming the Energy Vision" or REV program.

Among the 2015 plan's elements are a series of clean energy targets, including a 40% reduction in greenhouse gas emissions from 1990 levels; 50% of electricity generation coming from carbon-free renewables; and 600 trillion Btu in energy efficiency gains, which equates to a 23% reduction
from 2012 in energy consumption in buildings.

Whether and how New York will implement its 2015 State Energy Plan remains to be seen.  Notably, the plan was produced by the state's executive branch; it is unclear whether legislators will support or thwart it.  Will the Empire State follow its latest plan?  If so, will it lead to the anticipated economic opportunities?

Maine RGGI report 2015: price impact "relatively modest", programs helpful

Friday, June 12, 2015

For 8 years, states in the Northeastern U.S. have participated in the Regional Greenhouse Gas Initiative.  RGGI, the first market-based greenhouse gas regulatory program in the United States, represents a cooperative effort by participating states to cap and reduce greenhouse gas emissions from the electric power sector, coupled with a market for auctioning and trading emission allowances.  While some groups feared that the RGGI program would increase electricity prices, a recent report by the Maine Public Utilities Commission found that the impact of RGGI on electricity prices in Maine has been relatively modest -- while finding that RGGI-funded programs contribute to economic development and reduce greenhouse gas emissions.

RGGI formed in 2007, when ten states -- Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont -- agreed to first cap, and then slowly reduce, the greenhouse gas emissions of their electrical energy sectors by 10% by 2018.  While New Jersey withdrew in 2012, the program has remained strong; in 2014, the remaining states subsequently tightened the RGGI cap for 2014 from 165 million short tons of carbon to 91 million short tons, then further declining 2.5% per year from 2015 to 2020.

While each participating state adopted its own laws implementing RGGI, in general the RGGI laws require certain generators of electricity to track their carbon emissions and acquire an “allowance” for every ton of carbon dioxide or its equivalent that they emit.  States conduct periodic auctions of allowances, and market participants are free to engage in secondary market trades.  Generators must purchase or trade for enough emissions allowances to match the number of tons of CO2-equivalent emitted.  The cost of acquiring these allowances gives generators an incentive to improve their efficiency or switch to fuels with a lower carbon intensity.

Each state also adopted its own laws governing the use of funds raised by state auctions of RGGI allowances.  In Maine, most funds go to the Efficiency Maine Trust for purposes including measures, investments and arrangements that reduce electricity consumption or reduce greenhouse gas emissions and lower energy costs at commercial or industrial facilities, and for investment in measures that lower residential heating energy demand and reduce greenhouse gas emissions.

RGGI has conducted 27 quarterly allowance auctions since September 2008, through which Maine has received a cumulative total of $ 62.22 million in RGGI auction proceeds.  Maine’s auction proceeds in 2014 totaled $11.37 million. According to the Maine Public Utilities Commission's report:
the annual cost to Maine ratepayers of the RGGI program was approximately $0.0024 per kWh. For the average Maine residential customer using 530 kWh per month, the 2014 RGGI program cost was approximately $ 1.27 per month. For a commercial customer using 25,000 kWh per month the 2014 RGGI program cost was approximately $60.00 per month. A large commercial or industrial customer using 500,000 kWh per month would have had a 2014 RGGI program cost of approximately $1,200 per month.
On the benefits side of the ledger, the Commission's report cites a finding that "all RGGI proceeds since 2008 are expected to return more than $2 billion in lifetime energy bill savings to more than 3 million households and more than 12,000 businesses across the eight states taking part in RGGI."  The Commission also cited its July 2014 report to the Legislature quantifying the increases in employment, real personal income, and gross state product expected to occur in Maine as a result of the cap tightening and other changes implemented in 2014.  That report found:
economic impacts for the New England region include a cumulative increase in Gross Regional Product of over $2 billion, a cumulative increase in employment of 38,900 job-years, and a cumulative increase in real personal income of $1.5 billion including a cumulative increase in Maine Gross State Product of $200 million, a cumulative increase in employment of more than 5,000 job-years, and a cumulative increase in real personal income of $100 million.
Based on these observations, the Maine Public Utilities Commission's 2015 report on RGGI concludes that "the impact of RGGI on electricity prices has been relatively modest, while RGGI-funded programs contribute to the gross state product, job growth, and personal income, and also reduce greenhouse gas emissions."

Transmission line for Canadian imports advances

Tuesday, June 9, 2015

A proposed high-voltage direct current transmission line designed to import Canadian power into the New England grid has received a favorable environmental recommendation from the U.S. Department of Energy. 

The New England Clean Power Link is a high-voltage, direct-current transmission project proposed by TDI New England, a subsidiary of private transmission developer Transmission Developers Inc. and ultimately part of the Blackstone Group.

Designed to feed the New England market with up to 1,000 megawatts of electricity, the proposed $1.2 billion New England Clean Power Link project would feature two parallel cables approximately 5” in diameter, operating at a voltage of approximately 300 to 320 kV.  These HVDC lines would run about 154 miles.  Originating at a DC converter station in Quebec, the U.S. portion of the line would start at the international border in Alburgh, Vermont.  It would run beneath the bottom sediments of Lake Champlain for about 98 miles, then turn east and run over land (but underground, mostly under roadway rights-of-way and railway beds) to a terminal converter station in Ludlow, Vermont, where the power could flow onto the New England grid.

Federal law requires most infrastructure development for international trade in energy to apply for and receive a Presidential Permit before the project may be built.  TDI New England applied for the presidential permit in May 2014, and applied to the state of Vermont for permits in December 2014.

As part of the Presidential Permit process, the federal National Environmental Policy Act or NEPA requires the U.S. Department of Energy to evaluate the potential environmental impacts in the United Statesof the proposed action and the range of reasonable alternatives.  In this case, the proposed federal action is the issuance of a Presidential permit to the applicant, Champlain VT, LLC, doing business as TDI - New England, to construct, operate, maintain, and connect a new electric transmission line across the U.S.-Canada border in northern Vermont.

On June 3, the Department of Energy released its final draft Environmental Impact Statement or EIS for the New England Clean Power Link.  In that document, the Department found relatively minimal and short-term adverse environmental impacts from project construction, operation and maintenance. 

Once notice of the draft EIS is published in the Federal Register, the public will have 60 days to comment on its analysis.  The Department will also hold public informational meetings in Vermont regarding the project.  According to the EIS, TDI New England expects permitting will continue through mid-2016, with construction and in-service dates as early as 2018 and 2019 respectively.

Meanwhile, TDI is simultaneously pursuing other HVDC transmission lines from Canada into the Northeastern US, most notably the Champlain-Hudson Power Express -- another HVDC line beneath Lake Champlain but continuing on overland and under the Hudson River to a converter station in New York City.   The Champlain-Hudson Power Express won a Presidential Permit in 2014.

NYISO solar study announced

Thursday, June 4, 2015

Solar power is booming in the U.S. -- but how will growth in solar photovoltaic generating capacity affect the electricity grid?  The operator of the state of New York's electric grid has announced a study of the potential for growth in solar power resources to determine their impact on grid operations over the next 15 years.

Solar panels recently developed in a farm field in Massachusetts.
The New York Independent System Operator (NYISO) operates New York State's high-voltage transmission network, runs the state's wholesale electricity markets.  NYISO also evaluates trends in utility infrastructure development and usage, and what changes in these patterns imply for future infrastructure needs.

One such trend is the recent rapid growth in installed solar electric generating capacity.  In New York, a state government initiative known as NY-Sun aims to reduce solar installation costs by stimulating demand and increasing the number of solar PV systems installed in the state.  The NY-Sun program envisions the installation of more than 3,000 megawatts of customer-sited solar capacity by 2023, supported by about $150 million in annual state funding for solar PV projects.  Already, in the first two years of NY-Sun, a total of 316 megawatts of solar electric has been installed or is under contract.

Unlike standalone utility-scale solar development, the solar buildout directly triggered by the NY-Sun program will occur “behind the meter” — that is, on the customer's side of the utility meter, as opposed to a typical power plant sited remotely from customer load.  Nevertheless, increased consumption of power produced by distributed generation might affect NYISO's load forecasts or grid operations.  So too might the collective impacts of many generators with variable but correlated output.

To prepare for this future, NYISO has announced a "solar study" to evaluate the growing impact of sun-powered generation.  The study will focus on the following objectives:
  • Developing solar forecasting tools and preparing 15-year forecasts of solar PV capacity for each of the 11 load zones in New York State
  • Researching how other independent system operators and regional transmission organizations have integrated solar resources into their grids
  • Evaluating solar generation variability and its impact on customer load served by the NYS electric systems.
  • Reviewing operational impacts of various levels of solar and wind resources.

The results of NYISO's solar study are expected to be released in a report later this year.

FERC approves Iberdrola-UIL merger

Tuesday, June 2, 2015

Federal utility regulators have issued an order authorizing transactions the merger of utilities affiliated with Iberdrola, S.A. and UIL Holding Corporation.

Iberdrola is a Spanish-owned utility holding company, owning electricity and natural gas systems and electric generation across four continents.  Its direct wholly owned subsidiary Iberdrola USA holds all of Iberdrola’s energy-related operations in the United States through two intermediate holding companies. Iberdrola USA Networks, Inc., holds transmission owning public utility affiliates, including New York State Electric & Gas Corporation (NYSEG), Rochester Gas and Electric Corporation, Central Maine Power Company, Maine Natural Gas Company, and interests in Maine Electric Power Company. Iberdrola Renewables Holdings, Inc. owns and operates its generation segment in the United States through a number of indirect subsidiaries.

UIL is in the business of ownership of operating regulated utilities in Connecticut and Massachusetts. It owns and controls the United Illuminating Company, a business engaged in purchasing, transmitting, and distributing electric power to customers in southwestern Connecticut. United Illuminating owns a 50 percent equity interest in GCE Holding LLC which in turn owns two companies owning 187.6 MW dual-fuel generating plants in Milford and Middletown, Connecticut. UIL also owns natural gas local distribution companies in central and southern Connecticut and western Massachusetts, as well as Total Peaking Services, LLC which provides liquefied natural gas storage services.

On February 26, 2015, Iberdrola S.A. announced the boards of directors of Iberdrola S.A. and Iberdrola USA had approved a combination of Iberdrola USA with UIL Holdings in a friendly transaction, reportedly for about $3 billion.  On March 25, 2015, Iberdrola and UIL applied to the Federal Energy Regulatory Commission for authorization under section 203(a)(1) and (a)(2) of the Federal Power Act (FPA) for a series of transactions in which UIL will become an indirect wholly owned subsidiary of Iberdrola USA and, in turn, a wholly owned subsidiary of Iberdrola.

In a Section 203 case, the Commission examines a merger’s effect on competition, rates and regulation, and the potential for cross-subsidization.  Applicants must demonstrate that a proposed disposition or acquisition of jurisdictional facilities meets the standards of Section 203.   In the Iberdrola-UIL case, the applicants stated that their subsidiaries' portfolios of generation, transmission, natural gas assets, and other jurisdictional facilities had only de minimis overlap, that the transaction would not adversely affect rates or regulation, or result in cross-subsidization of a nonutility associate company or pledge or encumbrance of utility assets for the benefit of an associate company.

On June 2, 2015, the Commission issued an order finding that the proposed transaction is consistent with the public interest and is authorized, subject to routine conditions.  While other regulatory approvals may be required before the merger can proceed, securing prior authorization under Section 203 is an important milestone for the proposed deal.

According to Iberdrola, the combined company will have a 2014 pro forma EBITDA of approximately $2 billion, net income of $570 million, 3.1 million of points of supply, around 6.7 GW of installed capacity.  Iberdrola anticipates that the company will become the US's second largest wind operator and one of the nation's largest utilities.

Feds settle on final 2011 Southwest blackout penalty

Friday, May 29, 2015

Over four years after a major 2011 power outage in Southern California and parts of the Southwest, federal energy regulators have approved the sixth and final settlement of penalties for violations of law and reliability standards

After the September 8, 2011 blackout left more than 5 million people in Southern California, Arizona and Baja California, Mexico, without power for up to 12 hours, the Federal Energy Regulatory Commission began investigating what had happened.  After conducting that investigation jointly with electric reliability organization North American Electric Reliability Corporation (NERC), in an April 2012 report FERC found that the outage started when a 500-kilovolt transmission line owned by utility Arizona Public Service Company tripped.

The FERC continued its investigation into the 2011 Southwest blackout after its staff report was made public.  It identified six entities believed to have been involved: Arizona Public Service Company, the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.

FERC's enforcement process typically offers the accused an opportunity to agree to a stipulation of facts (for example, that the utility violated a particular reliability standard) and to pay a civil penalty and perform mitigation measures.  In its enforcement actions related to the 2011 Southwest blackout case, all six entities ultimately agreed to stipulations and penalties that were accepted by the Commission.

In July 2014, the FERC accepted Arizona Public Service's stipulation with NERC and FERC's Office of Enforcement, under which APS agreed to pay $3.25 million and improve its system reliability.  In August 2014, California's Imperial Irrigation District agreed to a $12 million fine.  Utility Southern California Edison agreed to a $650,000 fine in October.  In December, FERC settled with federal power marketing agency Western Area Power Administration with no penalty.  Grid operator California ISO agreed to pay $6 million.

This week the FERC announced a settlement with Western Electricity Coordinating Council.  WECC promotes grid reliability in the Western Interconnection, a broad area of the western United States.  According to the FERC order, FERC enforcement staff and NERC determined that WECC as the Reliability Coordinator violated nine requirements of the Interconnection Reliability Operations and Coordination (IRO) and the Facilities Design, Connection and Maintenance (FAC) groups of Reliability Standards.  Enforcement staff and NERC concluded that WECC failed to identify and prevent violations of system operating limits and Interconnection Reliability Operating Limits and was unaware of the impact of protection systems, and used an inadequate system operating limit methodology that exposed its area to cascading outages.

As a result, the settlement calls for WECC to pay a $16 million civil penalty.  $3 million of this will be split evenly between the U.S. Treasury and NERC, and $13 million will be invested in reliability enhancement measures that go above and beyond mitigation of the violations and the requirements of the Reliability Standards.  WECC and its successor as Reliability Coordinator, Peak Reliability, also agreed to mitigation and reliability activities and to submit to compliance monitoring.

FERC has described the WECC settlement as marking "final resolution" of the investigation by FERC Enforcement staff and NERC into the 2011 Southwest blackout.

Vermont resets renewable energy program

Tuesday, May 26, 2015

The Vermont legislature has voted to create the state's first renewable energy standards for electric utilities.  The bill, H.40, changes the way Vermont encourages the generation and use of renewably derived electricity.

Like most states, Vermont law has encouraged renewable energy development for over a decade.  In 2005 the state legislature created the Sustainably Priced Energy Enterprise Development, or SPEED, program to promote renewable energy development.  Under SPEED, the state encouraged its 18 utilities to enter into long-term contracts for power from renewable energy sources, with a goal that utilities source 20% of their supply from qualifying SPEED resources by 2017.  The SPEED program's goal has been to promote the development of in-state energy sources which use renewable fuels to ensure that to the greatest extent possible the economic benefits of these new energy sources flow to the Vermont economy in general and to the rate paying citizens of the state in particular.

But between recent controversy over possible "double counting" of renewable energy attributes produced and sold by Vermont utilities, and perennial interest in refining state energy policy, this year the Vermont legislature pursued H.40 as an attempt to fix Vermont's renewable energy programs.  H.40 will replace the SPEED goals with a Renewable Energy Standard and Energy Transformation, or RESET, program.  The RESET program includes a renewable portfolio standard requiring that 55 percent of a utility’s electricity come from renewables, including large-scale hydro power, by 2017, increasing 4 percentage points every three years until reaching 75% by 2032.

The bill also gives utilities an entrance into financing thermal efficiency for heating and cooling.  It will require utilities to offer incentives and on-bill financing for projects like weatherization and heat pumps.  To monitor and protect against impacts to customer rates, H.40 requires annual reports starting in 2018 on the RESET program's impact on electric rates, including 10-year forward projections.  It also allows utilities to seek waivers if they can show that compliance would increase electric rates.
Previous efforts to institute a mandatory renewable energy standard in Vermont were not successful, but this year versions of H.40 have now been approved by both chambers of the state legislature.  The Vermont House of Representatives passed H.40 on March 10, and the Senate approved an amended version on May 15.

Coal power plants retiring in 2015

Thursday, May 21, 2015

The U.S. portfolio of electric power plants will continue to shift in 2015, according to a federal assessment projecting that nearly 16 gigawatts (GW) of generating capacity will retire in 2015.  Most of the capacity to be retired this year is coal-fired generation.  This continues a multi-year trend away from coal, and toward natural gas and renewable resources.

According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015.  Of this, 81% (12.9 GW) is coal-fired generation.  Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW).  Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.

New environmental regulations and struggles to remain cost-competitive explain most of these retirements.  This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect.  MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies.  While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.

Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States.  According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units.  In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%.  The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources.  This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.

The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014.  At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid.  This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.

House subcommittee considers reliability draft

Tuesday, May 19, 2015

A congressional committee is considering legislation to assure reliability and security of the U.S. electricity grid.  The House Subcommittee on Energy and Power's discussion draft includes a series of provisions designed to harden the grid against disturbance.

To understand the discussion draft, you must first understand its context.  2015 is a time of great change for the U.S. electricity system.  The grid continues to shift away from coal-fired generation and towards use of natural gas and renewable energy sources.  New environmental regulations affecting power plants are taking effect.  Smart grid technology now enables real-time communication and coordination between supply and demand for electricity, but creates millions of potential access points for hackers to target the grid.  Meanwhile utilities plan to invest more than $60 billion in transmission infrastructure over the next decade. 

Faced with these shifts, the House Subcommittee on Energy and Power held a hearing today on a "discussion draft" of proposed measures to strengthen grid reliability, security and readiness to survive disturbance.  The discussion draft includes measures that would:
  • Resolve conflicts between choosing whether to comply with an emergency order from the Department of Energy or violate environmental obligations;
  • Require the Federal Energy Regulatory Commission to complete an independent reliability analysis of any proposed or final major federal rule that affects electric generating units;
  • Direct the Secretary of Energy to develop and adopt procedures to enhance communication and coordination between governmental entities and the private sector to improve emergency response and recovery;
  • Give the Secretary of Energy powers to address grid security emergencies, and facilitate information sharing;
  • Require the Energy Department to submit a plan to Congress evaluating the feasibility of establishing a Strategic Transformer Reserve for the storage, in strategically-located facilities, of spare large power transformers in sufficient numbers to temporarily replace critically damaged large power transformers;
  • Direct DOE to create a voluntary Cyber Sense program to identify cyber-secure products and technologies intended for use in the bulk-power system, like controls and SCADA systems;
  • Directs state public utility commissions and utilities to improve grid resilience and promote investments in energy analytics technology to increase efficiencies and lower costs for ratepayers while strengthening reliability and security; and
  • Require FERC to work with each regional transmission organization to encourage a diverse generation portfolio, long-term reliability and price certainty for customers, and enhanced performance assurance during peak period.
As noted in the opening statements of Chairmen Ed Whitfield and Fred Upton, elements from this discussion draft may be included in a bipartisan energy bill expected to emerge from the House committee later this session.

FERC proposes geomagnetic disturbance reliability standard

Thursday, May 14, 2015

Is the U.S. electric grid ready for solar storms and other geomagnetic disturbances?  Today the Federal Energy Regulatory Commission proposed approving a new reliability standard for the grid to address its vulnerability to these hazards.

A utility substation near Treasureton in southeast Idaho.

Periodic activity on the Sun's surface sends powerful waves of energetic particles toward the Earth.  These solar events can distort the Earth's magnetic field, affecting the flow of electricity on Earth.  While serious geomagnetic disturbances are expected to be infrequent, they can cause blackouts and damage key utility infrastructure.

The Federal Energy Regulatory Commission has jurisdiction over the reliability of the U.S.'s bulk electric power system.  To this end, it has designated the North American Electric Reliability Corporation (NERC) as the nation's electric reliability organization.  In May 2013, FERC directed NERC to develop and submit new standards for protecting the grid against geomagnetic disturbances (Order No. 779)

FERC and NERC have proceeded in a two-stage process.  First, in June 2014 FERC approved a standard on implementation of operating plans, procedures and processes to mitigate effects of geomagnetic disturbances (Order No. 797).

Reserved for the second stage were further requirements that transmission planners and owners assess the vulnerability of their systems to a theoretical benchmark event.  NERC subsequently proposed such a standard, calling for an evaluation of what would happen in a “one-in-100-year” benchmark event.

In a Notice of Proposed Rulemaking issued today, the FERC proposes to largely adopt NERC’s proposed second-stage standard.  The standard would require covered entities to have system models needed to complete vulnerability assessments, to have criteria for acceptable steady state voltage performance during a benchmark event, and to complete a vulnerability assessment once every 60 calendar months. If the assessment indicates that a system does not meet the performance requirements, the entity would have to develop a corrective action plan addressing how the requirements will be met.

The proposed rulemaking would direct NERC to further modify its standard to require that the study and benchmarking of geomagnetic disturbance events is based on a more complete set of data and a reasonable scientific and engineering approach.

Comments on today’s Notice of Proposed Rulemaking are due 60 days after its publication in the Federal Register.

Geomagnetic disturbances, and their impacts to the grid, are a hot topic in energy regulation at the present. States are considering laws regulating utility readiness for and response to geomagnetic disturbances; for example, next week the Maine Legislature’s Joint Standing Committee on Energy, Utilities, and Technology will consider LD 1363, An Act To Secure the Maine Electrical Grid from Long-term Blackouts.

ISO-NE projects slow growth in electricity demand

Wednesday, May 13, 2015

New England's electric grid operator predicts slow growth in annual energy usage in the region over the next decade, with slightly quicker growth in peak demand.

A Maine power plant -- the ecomaine Waste-to-Energy plant in Portland, Maine.

ISO New England, Inc. develops an annual long-term load forecast using factors including state and regional economic forecasts and 40 years of weather history.  Its most recent baseline forecast projects a compound annual growth rate of 1.0% in total energy usage in New England from 2015 to 2024.  For 2015, ISO-NE projects 138,745 gigawatt-hours (GWh) of load, growing to 152,280 GWh in 2024.

ISO-NE's forecast also projects future peak demand, a measure of the highest amount of electricity used in a single hour in New England.  Often, peak demand drives the need for constructing and maintaining power plants and transmission lines (and energy efficiency investments).  According to the latest ISO-NE forecast, New England's peak electricity demand is projected to rise by a compound annual growth rate of 1.3%, from 28,395 MW this year to 31,905 MW in 2024.

These baseline projections for future peak demand and energy usage take into account load reductions that can be expected from future installations of distributed solar photovoltaic facilities.  ISO-NE has prepared a separate Distributed Generation Forecast to estimate the load-reducing effects of distributed solar facilities developed as a result of state policy goals.

ISO-NE's baseline projections do not account for significant energy-efficiency savings, neither those committed through the region’s three-year Forward Capacity Market (FCM) nor future savings that can be expected beyond the FCM timeframe.

Report on Maine renewable portfolio standard in 2013

Wednesday, May 6, 2015

The Maine Public Utilities Commission has issued a report on Maine's use of renewable electricity in 2013.  The report shows the impact of Maine's renewable portfolio standard, a state law requiring electricity suppliers to source specified percentages of their electricity from “new” renewable resources.

Since 2000, Maine law has required electricity suppliers to include renewable energy in their portfolio of supply sources.  Maine’s original electric industry restructuring legislation included a 30% eligible resource portfolio requirement. The eligible resource portfolio requirement, now referred to as Class II, mandated that each retail competitive electricity supplier meet at least 30% of its retail load in Maine from “eligible resources.”  Eligible resources are defined in statute as either renewable resources or efficient resources.  Renewable resources are defined in statute as fuel cells, tidal power, solar arrays, wind power, geothermal installations, hydroelectric generators, biomass generators, and municipal solid waste facilities. Renewable resources may not exceed a production capacity of 100 megawatts. “Efficient” resources are cogeneration facilities that were constructed prior to 1997, meet a statutory efficient standard and may be fueled by fossil fuels.

During its 2007 session, the Maine Legislature enacted an Act to Stimulate Demand for Renewable Energy.  This Act established a new "Class I" standard, requiring Maine electricity suppliers to source specified percentages of their electricity from “new” renewable resources.  Generally, new renewable resources are renewable facilities that have an in-service date, resumed operation or were refurbished after September 1, 2005.  The Act set the initial renewable percentage requirement at 1% in 2008, increasing in annual one percentage point increments to 10% in 2017.  Pursuant to the Act, the renewable requirement will remain at 10% thereafter, unless the Commission suspends the requirement.

The Commission's March 31, 2015 report, Annual Report on New Renewable Resource Portfolio Requirement, reports on renewable portfolio standard compliance activity in calendar year 2013.  This lag between the study period and the report's issuance is driven by the timing of the most recently filed Competitive Electricity Provider (CEP) annual compliance reports, which were filed in July 2014 for calendar year 2013.  In 2013, the Act required suppliers to source 5% of their power from new renewable resources.  Suppliers can comply either by acquiring sufficient renewable energy certificates or RECs to cover their compliance obligation, or by paying an "alternative compliance payment".

According to the report, in 2013 suppliers purchased 727,291 Class I RECs from 21 certified generating facilities to meet the portfolio requirement.  Nearly 97% of these RECs came from biomass facilities located in Maine.  According to the report, 17 of the 21 facilities are biomass, three are hydro, and one is a wind facility.  18 of the 21 facilities are located in Maine, one is located in Connecticut, one is located in Massachusetts and one is located in Vermont.

The Commission's report also documents the cost of compliance in 2013.  During 2013, the cost of RECs used for compliance with the Class I requirement ranged from approximately $1.50 per MWh to $60 per MWh, with an average cost of $19. 8 7 per MWh and a total cost of $14, 292,438.  As noted in the report, the cost of Maine Class I RECs has dropped substantially since 2013, with the report citing a current trading range of $3.00 to $5.00.  With minor use of the alternative compliance mechanism by two suppliers, the total cost to ratepayers during 2013 was $14,296,249, which the Commission's report translates into an average rate impact of about 0.12 cents per kWh (about 60 to 65 cents monthly for a typical residential bill, or a residential customer bill impact of about 1%).

The report also documents the 2013 costs of RECs used to satisfy the "Class II" eligible resource portfolio requirement as ranging from $0.00 per MWh (some RECs were included as part of an energy transaction at no specified extra cost) to $1.00 per MWh, with an average cost of $0.16 per MWh and a total cost of $589,386. This translates into less than three cents per month on a typical residential bill.

Champlain Hudson Power Express gets Army Corps permit

Monday, May 4, 2015

The Champlain Hudson Power Express, an electric transmission line proposed from Quebec to New York, has completed its federal permitting process according to project developer Transmission Developers Inc.

Project developer TDI is a Blackstone portfolio company, with an apparent focus on HVDC lines.  First proposed in 2008, the current incarnation of the Champlain Hudson Power Express is a 333-mile high voltage direct current (HVDC) transmission line to be installed underground and underwater, from the U.S.-Canada border to New York City, running down Lake Champlain and parts of the Hudson River.  The line is slated to be able to import up to 1,000 megawatts of power from Canada to the U.S. 

In a press release issued last month, TDI announced that the U.S. Army Corps of Engineers has issued a permit that allows the Champlain Hudson Power Express project to be placed in waters of the United States along its proposed route.  The permit authorizes TDI to construct the project pursuant to Section 10 of the Rivers and Harbors Act and Section 404 of the Clean Water Act.

According to TDI, the Army Corps permit represents the final federal or state permit necessary to begin construction.  According to the permit, the work authorized must be completed by December 30, 2019.

More hydropower relicensure expected

Thursday, April 16, 2015

Many U.S. hydropower projects face relicensure by the Federal Energy Regulatory Commission within the next 3 years, making hydro project relicensing a hot topic.

The FERC is the nation's primary federal regulator of hydropower facilities.  Under Part I of the Federal Power Act, the Commission's responsibilities over hydropower include issuing licenses for the construction of new projects, relicensing for the continuance of existing projects, and oversight of all ongoing project operations, including dam safety inspections and environmental monitoring.

According to the Commission, about 1,023 issued licenses were active as of April 1, 2015.  Licenses are typically effective for up to 50 years, largely because dams and hydroelectric power facilities are typically long-lived assets and because the regulatory process for licensure is extensive (and expensive for project developers or owners).  Nevertheless, as time marches on, even a 50-year license will ultimately expire, so owners of FERC-licensed hydropower projects must eventually evaluate relicensure

Federal law and regulations, including Section 15(b)(1) of the Federal Power Act and 18 C.F.R. §5.5 of the Commission’s regulations, govern the relicensure process.  Between 5 and 5.5 years before an existing license expires, the licensee must notify the Commission whether or not it intends to file an application for a new license.  This filing is known as a Notice of Intent or NOI.  At the same time, the licensee seeking relicensure must also file a Pre-Application Document (PAD).  The PAD must include: (1) a process plan and schedule; (2) a description of the project’s location, facilities, and operation; (3) a description of the existing environment at the project and its resource impacts; (4) a preliminary list of issues and proposed studies; and (5) a list of contacts.  A licensee must also distribute the PAD to appropriate federal, state, and interstate resource agencies, Indian tribes, local governments, and members of the public likely to be interested in the project’s relicensing.

The Commission has noted an anticipated uptick in the rate of relicensure applications.  From October 1, 2010 through September 30, 2014, the Commission has received an annual average of about 12 Notices of Intent to relicense hydroelectric projects.  According to the FERC, 47 licensed projects were in the relicensure process as of April 1.  But even more projects face relicensure in the next 3 years.  According to an April 1 notice issued by the Commission, about 100 FERC-licensed hydropower projects will begin the relicensing process between October 1, 2016, and September 30, 2018.  The Commission thus anticipates the annual average number of Notices of Intent to increase to about 34.

Owners of FERC-licensed hydropower projects nearing the end of their license terms must plan ahead to prepare for relicensure.  Given the expected increase in hydroelectric project relicensure, Commission staff reasonably expects an increase in their workload.  While most existing projects have historically been able to win new licenses, in some cases hydropower project relicensing can become controversial.  Expect the next several years to bring increased relicensing activity.

Maine considers nuclear energy law change

Monday, April 13, 2015

The Maine legislature is considering a proposal to amend state laws regarding the siting and construction of new nuclear power plants. The bill known as LD 1313, "An Act To Amend the Laws Regarding Nuclear Power Generating Facilities", is listed as a "Governor's Bill", indicating its origin from Maine Governor Paul LePage. What might LD 1313 mean for Maine?

Maine is not currently home to any operating nuclear power plants.  From 1972 to 1996, the Maine Yankee Nuclear Power Plant operated a 900 megawatt reactor in Wiscasset.  While it operated, Maine Yankee was the state's largest generator of electricity.  But a Nuclear Regulatory Commission investigation launched in 1995 identified safety and other problems that ultimately rendered continued plant operation uneconomic; the site was decommissioned from 1997 through 2005, with spent fuel remaining on site to date.

Maine Yankee was controversial from its inception, with significant opposition to its construction from anti-nuclear groups and others.  Partially in response to this controversy, in 1987 Maine enacted a law "to provide for citizen participation in any decision to construct a nuclear power plant within the State."  As part of that law (as amended in 1999), the Legislature enacted a finding "that construction of a nuclear power plant is a major financial investment, which will have consequences for consumers for years to come."  The law also included a finding that, "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers."  In addition, the law required a statewide voter referendum prior to the construction of any nuclear power plant in Maine, and prohibited construction of a nuclear power plant without this voter approval.

Governor LePage's proposal would amend those two sections of existing law relating to the process for siting nuclear power plants.  First, LD 1313 would delete the legislative finding that "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers." Second, LD 1313 would limit the referendum requirement to nuclear power plants "with capacity greater than 500 megawatts."

LD 1313 would appear to encourage the construction of relatively small nuclear power plants in Maine -- that is, those with capacity of 500 megawatts or smaller, roughly half of Maine Yankee's size.  But of the approximately 100 nuclear power plants in commercial operation in the U.S. today, nearly all can generate more than 500 megawatts of power.  The Omaha Public Power District's Fort Calhoun plant in Nebraska is rated at 476 megawatts, and is one of the only commercial reactors in the U.S. smaller than 500 megawatts.  The technical and security aspects of nuclear power have traditionally pushed utilities to develop relatively large nuclear power plants, making the development of small but traditional nuclear power in Maine relatively unlikely.

Perhaps more likely to benefit if LD 1313 is enacted would be the development of small modular nuclear reactors.  According to the U.S. Department of Energy, small modular reactors offer the advantage of lower initial capital investment, scalability, and siting flexibility at locations unable to accommodate more traditional larger reactors.  They also have the potential for enhanced safety and security.  The Department of Energy has expressed interest in advancing small modular reactor technology.  If LD 1313 is enacted, it could eliminate the requirement of statewide voter approval of the construction of a nuclear power plant using small modular reactor technology.

But whether LD 1313's enactment would actually lead to the construction of small modular reactors in Maine is unclear.  Is the voter referendum requirement really the chief obstacle to small modular reactor construction in Maine?  Or can Maine's lack of small modular reactors be explained by other limitations -- like technology, financing, or safety regulations?

LD 1313 has been referred to the Maine State Legislature's Joint Standing Committee on Energy, Utilities and Technology.  To date, no public hearing has been scheduled.