Maine community solar procurement bill, LD 1444

Wednesday, April 26, 2017

This week a committee of the Maine state legislature is scheduled to hold a public hearing on a bill that would direct state regulators to enter into long-term contracts to procure 120 megawatts of large-scale community solar distributed generation resources by 2022.  While Maine law currently allows some community-scale solar development, LD 1444, An Act Regarding Large-scale Community Solar Procurement, would create new structures geared toward state-sponsored long-term contracts and could open the door to broader ownership of or participation in community-scale solar in Maine.

If enacted into law as drafted, the bill would direct the Maine Public Utilities Commission to hold a series of four annual competitive solicitations by January 1, 2022.  Each solicitation would seek to procure 30 megawatts of large-scale community solar distributed generation resources.

Through an initial solicitation to be held by March 1, 2018, the Commission would set a uniform clearing price or "standard solar rate" for all awarded bids in the initial procurement.  Subsequent procurements would be subject to a declining block contract rate, under which the Commission would reduce the rate relative to the previous procurement by up to 3%.  But if the Commission were to conclude that a subsequent solicitation was not competitive, no bidders may be selected and the capacity available in that solicitation will be deferred to a subsequent solicitation.

Any resource selected for contracting would be offered a standard contract for a term of 20 years at the specified contract rate.  The resources' counterparty would be a "standard buyer" whose mission would be to "aggregate the output of the portfolio of distributed generation resources procured pursuant to this chapter and sell or use the output of these resources in a manner that maximizes the value of this portfolio of resources to all ratepayers."  Initially, the bill designates each investor-owned transmission and distribution utility as the standard buyer for its own service territory, but it would allow the Commission to designate another entity if doing so is in the best interest of ratepayers.  The benefits and costs of the procurement, shall be tracked and reviewed annually, and any gains would be allocated to from ratepayers of the project's host utility -- just as any losses would be recovered from those ratepayers.

On the project side, LD 1444 would establish a sponsor/subscriber model for large-scale community solar distributed generation resources.  A project sponsor would own or operate the resource.  A customer could subscribe for a proportional interest in such a resource, sized to represent at least one kilowatt of the resource's generating capacity.  Several additional requirements include:
  • The total expected annual value of all of a customer's subscriptions must not exceed 120% of the customer's most recent annual electricity bill. 
  • At least 50% of the subscriptions to a large-scale community solar distributed generation resource must be for 25 kilowatts or less, unless a municipality accounts for more than 50% of the subscriptions to a large-scale community solar distributed generation resource.
  • A municipality may not account for more than 70% of the subscriptions to a large-scale community solar distributed generation resource.
Once under contract, a project sponsor and subscribers receive the contract rate for the output of a large-scale community solar distributed generation resource that is fully subscribed. For any portion not subscribed, the project sponsor receives the wholesale rate.  Each subscriber will be allocated a bill credit based on its percentage interest of the facility's total production for the previous month.  These credits must be applied against the subscriber's monthly electricity bill.

LD 1444 is scheduled for a public hearing before the Committee on Energy, Utilities and Technology on April 27, 2017.

Maine PUC releases 2015 renewable report

Wednesday, April 19, 2017

Maine energy regulators have released a report on the state's electricity renewable portfolio standard, presenting data from 2015.  The Maine Public Utilities Commission's Annual Report on New Renewable Resource Portfolio Requirement - Report for 2015 Activity [PDF] provides a look at Maine's renewables law, now in its tenth year on the books.  It may also inform legislative discussions later this spring about the future of Maine's renewable portfolio standard.

In 2007, the Maine legislature enacted a law requiring that specified percentages of electricity that supply Maine’s consumers come from “new” or Class 1 renewable resources, ranging from 1% in 2008 to 10% in 2017.  The law also required the Commission to report annually to the legislative energy committee on the status of this requirement and related compliance matters.

According to the report, Maine suppliers sourced approximately 891,757 renewable energy certificates or RECs, from 30 facilities, to comply with the 2015 requirement.  Of these, 20 facilities were fueled by biomass, 4 by hydropower, 3 by wind and 1 by landfill gas.  25 out of the 30 facilities were located in Maine, with 2 in New York, and one each in Connecticut, Massachusetts, and Vermont.  By REC volume, 99% came from facilities located in Maine.

The report also estimates the cost to Maine ratepayers of Maine's new renewable resource portfolio requirement.  According to the report, the cost of RECs used for compliance in 2015 ranged from "approximately $2.00 per MWh to $42.50 per MWh, with an average cost of $13.16 per MWh and a total cost of $11,738,174."  Adding in $3,018 in alternative compliance payments by one supplier, the report estimates a total cost to ratepayers during 2015 of $11,741,192.  The report translates this total cost into "an average rate impact of about one-tenth of a cent per kWh. This is equivalent to about 55 cents per month, or 1%, for a typical residential customer; $50 per month for a medium commercial customer that uses 50,000 kWh per month; and $500 per month for a large commercial/industrial customer that uses 500,000 kWh per month."

Maine law also includes a Class 2 renewable portfolio standard, requiring an additional 30% of electricity come from existing renewables and other Class 2 resources.  According to the Commission's report, the average cost of a Class 2 REC in 2015 was $0.28 per MWh, with a total cost of $965,818.  The report notes that this is "equivalent to about 5 cents per month for a typical residential customer, and $4 and $40 per month for medium and large commercial/industrial customers with the usage levels described above, respectively."

This session, the 128th Maine Legislature is considering several bills that could affect Maine's renewable energy laws, including LD 532, An Act To Remove the 100-megawatt Limit on Hydroelectric Generators under the Renewable Resources Laws, as well as LD 1185, a concept draft which "proposes to enact measures designed to update Maine's renewable portfolio standards."

Brewer Anheuser-Busch InBev sets global renewable electricity goal by 2025

Thursday, April 6, 2017

World’s largest brewer Anheuser-Busch InBev SA – parent to brands including Budweiser, Corona, Rolling Rock, Michelob, and Stella Artois – has committed to sourcing its electricity entirely from renewable sources by 2025.  The move would make AB InBev the largest corporate direct purchaser of renewable electricity in the global consumer goods sector.

AB InBev makes 30% of the world’s beer, operating breweries in 50 countries. Collectively, these facilities consume 6 terawatt-hours of electricity a year, of which 7% is currently renewable-sourced.  According to a March 28 press release, changing to 100% renewable electricity will reduce the company's carbon footprint by 30%, an estimated reduction of about 2 million tons of carbon dioxide a year.

While many multinational companies “invest” in renewables by buying renewable energy credits or certificates known as "RECs", AB InBev’s plan involves no REC-buying. The company reportedly intends to obtain 75 to 85 percent of its electricity through direct power purchases under a power purchase agreement or similar commercial arrangement, with remaining 15 to 25 percent coming from on-site distributed generation installations at its facilities, like solar panels. The company has committed to producing the energy in the country in which it is to be consumed.

Sourcing renewable energy is relatively easier in some countries, like Mexico. AB InBev announced that its largest facility, a Grupo Modelo brewery, had signed contracts to get all its electricity from wind power, including 220 MW to be built by Iberdrola SA in Puebla. Those new wind projects alone, destined to supply the brewery, represent a 5% increase to Mexico's renewable energy capacity. But in other countries, most notably in Africa, a lack of markets and infrastructure to connect industrial consumers with renewable energy may prove challenging. Also worth noting is that the company's commitment relates to electricity, and not directly to fuels or heat required for beer production and distribution. 

Nevertheless, Anheuser-Busch InBev's commitment to sourcing 100% renewable electricity by 2025 across its global portfolio of facilities represents another data point in the trend of corporate direct investment in renewable energy.  Corporations including Apple, Google, and Amazon have made a variety of commitments relating to renewable electricity, citing benefits ranging from environmental sustainability to locking in power pricing.

Trump executive order on domestic energy policy

Thursday, March 30, 2017

U.S. President Donald Trump has signed an executive order affecting domestic energy policy.  His March 28, 2017 Presidential Executive Order on Promoting Energy Independence and Economic Growth includes a variety of directives, generally aimed at reducing federal regulations affecting domestic energy production.  Here's a look at his Executive Order targeting Obama-administration climate regulations and other agency actions that potentially burden the development or use of domestically produced energy resources.

The Executive Order includes 8 operative sections.  One provides policy statements; six call for regulatory reviews that could lead to rule changes or revocations, or directly revoke and rescind Obama-era actions.  The final section includes general provisions.

Section 1 includes five policy statements, such as that "is in the national interest to promote clean and safe development of our Nation's vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation."  It also sets a federal policy "that executive departments and agencies (agencies) immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law."

Section 2 calls for an immediate review of all agency actions that potentially burden the safe, efficient development of domestic energy resources, "with particular attention to oil, natural gas, coal, and nuclear energy resources."  It directs agency heads to submit a memorandum to the Office of Management and Budget detailing such potentially burdensome actions, and including "specific recommendations that, to the extent permitted by law, could alleviate or eliminate aspects of agency actions that burden domestic energy production."  With respect to actions targeted with specific recommendations in a final report, agency heads are directed to "as soon as practicable, suspend, revise, or rescind, or publish for notice and comment proposed rules suspending, revising, or rescinding, those actions, as appropriate and consistent with law."

Section 3 rescinds or revokes a variety of Presidential actions and reports, including several of President Obama's executive orders regarding climate change, the President's 2013 Climate Action Plan, and the Council on Environmental Quality's 2016 final guidance for federal agencies on consideration of greenhouse gas and climate issues in performing reviews of agency actions under the National Environmental Policy Act.

Section 4 calls for the Administrator of the Environmental Protection Agency to "immediately take all steps necessary to review" the Clean Power Plan governing electricity-sector emissions and related rules "for consistency with the policy set forth in section 1 of this order and, if appropriate, shall, as soon as practicable, suspend, revise, or rescind the guidance, or publish for notice and comment proposed rules suspending, revising, or rescinding those rules."

Section 5 disbands a working group on the social cost of greenhouse gas emissions, and restricts the ways agencies may account for the monetary value of changes in greenhouse gas emissions resulting from regulations.

Section 6 calls for the Secretary of Interior to lift moratoria on federal land coal leasing activities imposed under a 2015 order, and to commence federal coal leasing activities.

Section 7 calls for review of federal regulations affecting emissions from the oil and gas sector, including 2016 emissions standards for new, reconstructed and modified sources, and a 2015 rule governing hydraulic fracturing on federal and Indian lands, among others.

Section 8 includes general provisions, generally similar to those found in other executive orders.


MA net metering, Single Parcel and Subdivision rules

Tuesday, March 28, 2017

Massachusetts utility regulators have opened an inquiry to review the current standards and procedures by which distributed generation projects seek exceptions to the net metering rules and regulations that generally require each facility to be sited on a single parcel of land.  The case could lead to changes in the Department of Public Utilities' Single Parcel Rule and Subdivision Rule.

On March 15, 2017, the Massachusetts Department of Public Utilities issued an order opening an inquiry relating to the application of its net metering rules, which it docketed as DPU 17-22.  As described in that order, under Massachusetts statutes and regulations, "net metering allows customers to generate credits for excess electricity that net metering facilities generate."  The rules include limitations on the size of a generation facility eligible for net metering -- below 60 kW generally, or up to 2 MW for renewable projects (or 10 MW for certain public facilities).

Because the rules include project size limits, how you define the "facility" can affect its eligibility for net metering.  In one case, the Department established a "Single Parcel Rule", defining an eligible net metering facility as “the energy generating equipment associated with a single parcel of land, interconnected with the electric distribution system at a single point, behind a single meter." In 2016, the Department received 13 petitions seeking an exception to the Single Parcel Rule, an increase over three petitions in 2015 and one petition in 2014.

The Department also recognized if it was adopting parcel boundaries as a factor for defining a net metering facility, it should also set a date after which it would presume that the further subdivision of parcels was to game the net metering rule.  In its Subdivision Rule, the Department required that any customer who seeks to establish a net metering facility on a parcel of land that was subdivided after January 1, 2010, file a petition demonstrating that the subdivision was not for the purpose of creating multiple parcels specifically to support multiple net metering facilities.

But in a move that could lead to changes to these regulations, in its March 15 order opening inquiry, the Department identified a series of questions on which it seeks written comment.

Questions posed by the Department relate to the aggregation of capacity, blanket exemptions and case-by-case exemptions, the treatment of multiple facilities on one parcel, the treatment of a single facility on multiple parcels,  possible methods of streamlining submission and review of petitions for exceptions from the net metering rules and regulations, process requirements for petitions for exemptions, and challenges in allocating credits to multiple accounts and related solutions.

The Department has requested initial written comments no later than 5:00 p.m. on April 10, 2017.  It has also scheduled a technical conference for May 3, 2017.

Emerging technologies and the electric grid

Monday, March 27, 2017

A task force examining the deployment of emerging technologies across the North American electric grid has identified three imperatives necessary to ensure the continued reliability and efficiency of the bulk electricity system, relating to: renewable supply and integration; greater situational awareness; and controlling an increasingly distributed energy system, with increased deployment of distributed energy resources.

The 39-page report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust electricity system,” was published on March 16, 2017, by a group of nine Independent System Operators (ISO) and Regional Transmission Organizations (RTO) known collectively as the ISO/RTO Council (IRC).

With respect to integrating renewable resources, the IRC noted that it "[s]upports policies and positions recognizing the electricity system’s ability to accommodate large amounts of renewables and realizing their growing potential."  While remaining "agnostic to specific technologies that may faciiltate renewable integration", IRC supports policies that accommodate emerging renewable integration technologies, while "avoiding early technological lock-in."

With respect to situational awareness, the IRC notes the lack of available data on the penetration of distributed energy resources, but that a lack of data or its sharing should not limit grid operators' understanding of what's happening on the grid.  IRC suggests the development of a general operational data framework, "where increasingly comprehensive operational data from the distribution system is provided as DER penetrations reach different thresholds."

The report also notes, "Because of emerging technologies, North America’s electricity systems are moving toward a more distributed arrangement." In 2016, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking in which it proposed rule changes "to remove barriers to to the participation of electric storage resources and distributed energy resource aggregations" in organized wholesale electric markets.  Recognizing that such a rule change could set a framework for future DER growth, the IRC calls for continued coordination, data sharing, and flexibility.

Maine net energy billing rules, 2017 revision

Monday, March 20, 2017

On January 31, 2017, the Maine Public Utilities Commission adopted revisions to its rule chapter 313, governing net energy billing.  Net metering, or net energy billing, is the metering and billing mechanism that Maine and most other states have adopted to promote the development of solar photovoltaic and other distributed renewable energy facilities.  While the Commission first adopted a net energy billing rule in the early 1980s, its 2017 revisions to that rule reduce the benefits of net metering for future projects.  Here's a look at Maine's revised net energy billing rules.

The Commission described its actions in a written order dated March 1, and published its final rule on the same date.   Most notably, the Commission reduced the amount of future generation facility output that can be netted against its transmission and distribution utility bill -- by first introducing, then reducing, a concept called "nettable energy."  Nettable energy is now the entire amount of energy generated by the facility, including the amount consumed by a customer “behind-the-meter”.  This shift -- from netting on a net basis, to netting on a gross basis -- is a significant change in state policy that is unfavorable for behind-the-meter generation.

As before, a net energy billing customer with solar or other eligible generation may offset all of its energy supply bill with its nettable energy.  But the Commission's new rule phases out the former 100% crediting of net energy for transmission and distribution charges.  Depending on the year into which a project is placed in service, the new rule reduces the portion of the "nettable output" -- what counts for netting -- by 10% in each of the next 10 years, reaching 0% T&D crediting for customers that become net energy billing customers after calendar year 2026.  The result is a gradual reduction of the incentive to net energy bill.  (Note that once a customer becomes a net energy billing customer, its rate treatment will generally last for 15 years.  Likewise, existing net energy billing customers may continue to net bill under the previous rule's approach for a 15-year period, after which they could continue to net for supply but not for T&D.)

The Commission also added a section covering renewable energy credit (REC) aggregation.  Section 4 of Chapter 313 provides that new customers in 2018 and after may elect to have the RECs or environmental attributes of project power be aggregated by their local investor-owned utility for sale into the regional market, with the proceeds returned to participating customers.  The Commission described its decision to include a REC aggregation program as "an effort to obtain on an optional basis a value stream that is not currently being monetized."  If small renewable projects would qualify for RECs, but are either not doing so or are not selling the RECs, REC aggregation options may allow some projects to connect with the market.  On the other hand, by selling the RECs, the project owner or power consumer cannot claim to have consumed green electricity, so there are tradeoffs.

The Commission did not change some other aspects of the rule, such as maximum project size (660 kW) or its limit on the number of accounts or meters permissible under a single net energy billing arrangement (10).  It noted, "Fundamental changes to NEB in Maine and promotional programs for larger renewable and community solar projects are the purview of the Legislature as a matter of State energy policy."

Based on a list of legislative requests, the state legislature will consider at least 12 bills relating to solar energy in its 2017 session.

On March 10, the Commission published a Frequently Asked Questions document covering the Chapter 313 net metering rules.  The FAQ provides answers to 10 questions, ranging from why the Commission changed the rule, to providing specific examples of how much nettable energy a customer would be able to claim depending on the year in which its project was placed in service.

US auctions North Carolina offshore wind sites

Friday, March 17, 2017

Yesterday the U.S. Bureau of Ocean Energy Management completed a competitive lease sale for renewable wind energy development in federal waters offshore North Carolina.  Avangrid Renewables, LLC won the auction-based sale with a high bid of $9,066,650.  As a result, it has the right to lease 122,045 areas of ocean space in the designated Kitty Hawk Wind Energy Area.

The Kitty Hawk Wind Energy Area sits 24 nautical miles from shore, off the northeast coast of North Carolina by the Virginia border.  The base roughly triangular area extends 25.7 nautical miles in a general southeast direction, with a seaward apex in the northeast.  Using the National Renewable Energy Laboratory’s estimates of 3 megawatts per square kilometer, the lease area has a potential generating capacity of 1,486 megawatts.

BOEM announced the Kitty Hawk auction in January 2017.  Its conclusion yesterday represents the first federal offshore wind lease sale under the Trump administration.  According to BOEM, three other bidders particiated in the auction: Wind Future LLC, Statoil Wind US LLC, and wpd offshore Alpha LLC.

The North Carolina auction was BOEM's seventh competitive lease sale.  In all, competitive lease sales have raised about $67 million for the federal government.  While no commercial offshore wind projects are currently operating in federal waters, the Deepwater Wind Block Island project off Rhode Island began commercial operation last year.

FERC to hold session on state policies, wholesale markets

Wednesday, March 8, 2017

U.S. energy regulators have scheduled a two-day technical conference to consider how state energy policies affect wholesale electricity markets.

In a March 3 notice of technical conference, the Federal Energy Regulatory Commission gave public notice that it will hold a technical conference on May 1 and 2, 2017.  The notice describes tensions between competitive wholesale energy and capacity markets and state policies.  On the one hand, the Commission noted, "Competitive wholesale energy and capacity markets bring value to customers by efficiently pricing energy and capacity , taking into account the operational needs and the dynamics of the transmission system , and providing transparent signals for investment and retirement of resources."  Generally speaking, these wholesale competitive markets currently select resources based on principles of operational and economic efficiency without specific regard to resource type

But on the other hand, the Commission notes recent increases in "interest by state policy makers to pursue policies that prioritize certain resources or resource attributes" (such as renewable resources, or in-state resources).  That has led to what the Commission calls an "open question": "how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets and economic resource selection." These topics have come up in discussions relating to several eastern regional transmission organizations and independent system operators, such as the IMAPP process in New England, and similar efforts in PJM and NYISO to consider the integration of public policy into markets.

To foster further FERC-level discussion about the development of regional solutions that "reconcile the competitive market framework with the increasing interest by states to support particular resources or resource attributes," the Commission has scheduled the May 1-2 technical conference. The notice specifically references a range in potential long-term expectations regarding the relative roles of wholesale markets and state policies in shaping the resource mix -- ranging from no state role on the one end, to state authority over resource selection that must be accounted for in wholesale market design -- and a variety of potential solutions in between.

Anyone who wishes to participate in the conference may submit a nomination form to FERC online by 5:00 p.m. on March 17, 2017. 

Oroville Dam evacuation and relicensing

Tuesday, February 14, 2017

A California dam in the midst of a federal relicensing process has experienced flooding and storm-related damage, prompting the evacuation of over 180,000 people.  Evacuation orders and a reservoir drawdown represent the most rapid responses to the Oroville Dam incident -- but future discussions of engineering, dam safety, and public policy are likely to continue after the emergency has been resolved.

Oroville Dam is the tallest dam in the U.S.:  a 770-foot high earthfill embankment dam on the Feather River in northern California.  The dam was built from 1961-1968 by the California Department of Water Resources, as part of the State Water Project.  The resulting impoundment, Lake Oroville, can store over 3.5 million acre-feet of water, making it California's second largest man-made lake.

The Oroville project is subject to licensing by the Federal Energy Regulatory Commission under the Federal Power Act.  Its first license was issued on February 11, 1957, for a 50-year term which expired on January 31, 2007.  The Department of Water Resources filed an application for a new license for the project, which remains pending in Docket No. P-2100, although a settlement agreement was also filed.  In the meantime, the project continues to operate under a series of annual licenses issued by the Commission.  According to a DWR website, it "anticipates that FERC will issue a new license order in 2017 pending issuance of the aquatic biological opinion from the National Marine Fisheries Service."

According to state documents, California was hit by three major storms during January and February 2017, with major rain and runoff.  As Lake Oroville reached its full capacity, operators opened a spillway to allow excess water through the dam.  But on February 7, the spillway began to erode.  Four days later, operators opened the auxiliary emergency spillway, but eventually determined that this too was "in danger of failing."  Since a failure could cause widespread and severe flooding, officials called for evacuations downstream in the Feather River Valley.  On February 12, Governor Edmund G. Brown Jr. issued an emergency order strengthening the state's response.

Focus for now remains on safely resolving the risks that the Oroville Dam or its spillways might fail in a way that releases damaging waters.  The Commission could investigate what happened under its authority over the project through its existing license.  It could also raise issues relating to the incident in the context of the project's relicensing.  That case has been pending for roughly a decade, with a settlement agreement having been reached years ago.  But it is possible that the 2017 Oroville Dam incident could have consequences in the relicensing context, such as revised spillway designs or operating plans that could be reflected as conditions in a new license.

Teton County power outage in focus

Friday, February 10, 2017

What happens when a storm damages utility transmission towers?  Some consumers in the Teton Village area near Jackson, Wyoming, are facing multi-day power outages as local utility Lower Valley Energy scrambles to restore power safely.

Lower Valley Energy is a cooperative serving about 29,000 electricity customers in wesstern Wyoming and southeast Idaho, including the Jackson area.  Its 2015 financial statements describe about $126 million in net utility plant, and operating revenues of about $52 million. 

The Teton County outage started on the evening of February 7, 2017.  The utility announced that at least 10 transmission poles had buckled, causing a "major outage in Teton County."  At the time, it noted that while it did not yet know why the lines fell, wind gusts had been documented over 90 miles per hour.  The utility estimated up to 4,000 customers were without power the next morning, including the Teton Village area, Jackson Hole Mountain Resort ski area, and the airport.

Ultimately, the utility discovered that 17 steel transmission poles had buckled, among other failures. Lower Valley Energy announced a plan to replace them temporarily with wooden poles to restore power, and to "re-route power, hopefully at least on an intermittent basis, to the airport area."  But the damage to the transmission system serving Teton Village led the utility on February 8 to describe an expectation that Teton Village would be without power for 5-7 days.  This would lead the ski area to announce that it will "not be operating until further notice."

Later on February 8, the utility announced that the Jackson Hole airport was fully operational with its own backup generation, but restoring power to Teton Village could take days.  On the next morning, it announced that it had not been "successful in energizing the Teton Village Fire Department and facilities yesterday due to other outages in the valley," but that it hoped to accomplish that day.

Utility reliability comes at a cost, but also provides a value.  Businesses, local people, and visiting vacationers expect reliable access to electricity, but storms and their effects on infrastructure can be unpredictable.  An outage places issues of utility reliability in sharp focus.  After power is restored, questions for follow-up might include how the transmission towers failed, how the utility responded to the incident, and what should be done in the future to prevent similar incidents. Businesses, institutions (like the fire station) and people affected by the Teton County outage might consider how they could reduce their exposure to the risk of a prolonged utility outage -- for example, solar panels or other distributed generation, or battery backup -- and whether the cost is worth the benefit.

NH energy efficiency resource standard workshops

Monday, February 6, 2017

Following the New Hampshire Public Utilities Commission's adoption last summer of an energy efficiency resource standard, a regulatory board has scheduled a series of workshops to allow public input on how utilities serving the state plan to met the standard over the next three years.

On August 2, 2016, the Commission issued its Order No. 25,932, approving a settlement agreement establishing an energy efficiency resource standard or EERS.  The Commission described the EERS as "a framework within which the Commission’s energy efficiency programs shall be implemented," effective January 1, 2018.  Compared to previous energy efficiency structures, the EERS represents a a long term, binding energy savings target consistent with a policy directive to capture all cost-effective energy efficiency.  According to a public notice issued by the Commission, "Implementation of an EERS is expected to increase investment in cost-effective energy efficiency resources, reduce energy costs for NH ratepayers, and create new jobs."

As implementation of the standard nears, the Energy Efficiency Resource Standard (EERS) Committee of the state's Energy Efficiency and Sustainable Energy Board has scheduled a series of stakeholder workshops to allow stakeholders and the general public "the opportunity to influence, early in the planning process, how utilities serving the state are intending to achieve the EERS over the next three years." Workshop topics announced so far include residential, municipal, and commercial and industrial programs; how to evaluate program cost-effectiveness; project finance and program marketing; and evaluation, measurement and verification.

Workshops have been scheduled through March 3, 2017.  Utilities are expected to file a proposed EERS plan with the EESE Board by April 1, 2017, with a final plan to be filed with the Commission by September 30 for approval by December 31.

Maine 2017 solar, energy legislative proposals

Friday, February 3, 2017

The 128th Maine Legislature's first session kicked off last month in Augusta.  Over 2,000 legislative requests or proposed bills were submitted for the 2017 session, most of which will eventually be "printed" or released to the public as bills or "Legislative Documents."  Energy items on this session's docket are expected to include a variety of bills addressing solar energy.  While most of these bills have yet to be printed, energy-related bills that have been printed so far include items related to protecting the grid against geomagnetic disturbances and electromagnetic pulses, consumer protection in the form of limits retail electricity rates, and retooling the Governor's energy office:

  • LD 255, An Act To Implement Electric Grid Reliability Recommendations: as drafted, this concept draft proposes directing the Maine Public Utilities Commission to take certain actions regarding geomagnetic disturbances and electromagnetic pulses on the State’s electric grid, including installation of equipment to enable grid monitoring and protection. 
  • LD 259, An Act To Limit Rates Charged by Competitive Electricity Providers: as drafted, this bill would prohibit competitive electricity providers from charging a residential consumer a rate for generation service that is higher than the applicable standard-offer service rate.
  • LD 260, An Act to Create the Maine Energy Office: as drafted, among other changes this bill would revamp the Governor's Energy Office into a Commissioner-led office, with funding from Efficiency Maine Trust.
Beyond the bills that have been printed so far, a list published by the Legislative Information Office of bill titles organized by subject matter shows 12 legislative requests relating to solar energy:
  • LR 19, An Act To Encourage and Support Solar Energy for Use in the Private and Public Sectors 
  • LR 34, An Act To Grow Maine's Economy through Increased Solar Power Generation
  • LR 179, An Act To Enhance the Commercial Development of Solar Energy
  • LD 394, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development
  • LR 402, An Act To Promote the Development of Solar Energy in Maine
  • LD 529, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development
  • LR 1071, An Act To Protect and Expand Access to Solar Power in Maine
  • LR 1367, An Act Regarding Solar Power for Farms and Businesses
  • LR 1424, An Act To Advance Locally Owned Solar Energy Systems
  • LD 1425, An Act To Modernize Community Solar Policy
  • LR 1856, An Act Regarding Large-scale Community Solar Procurement
  • LD 1944, An Act To Address Solar Power in Maine 
The Joint Standing Committee on Energy, Utilities and Technology will hold public hearings on bills referred to it over the course of the session.  

National park solar microgrid proposed

Wednesday, February 1, 2017

The National Park Service has proposed a solar-powered microgrid to replace a power line in a remote area of Great Smoky Mountains National Park.  If developed, the Mt. Sterling Sustainable Energy Project could serve as an example of microgrids as cost-effective alternatives to transmission or distribution lines.

Solar panels on a campground facility inside Arches National Park, Utah.

Great Smoky Mountains National Park is located in a rugged area of North Carolina and Tennessee.  Today, NPS radio equipment located at the Mt. Sterling Fire Lookout Tower is powered by a 3.5-mile overhead line.  According to the NPS, "Maintaining the line is challenging and expensive based on its remote location and steep terrain."

As an alternative, Duke Energy has proposed installing a microgrid to power the radio equipment at the old fire tower: 30 solar panels tied to a zinc-air battery.  This solar microgrid would then operate separately from the interstate electricity grid, and according to NPS "would allow greater reliability while using a renewable energy source."  While its estimates suggest 10 trees would need to be cleared for site development and to prevent shading, NPS notes that "the microgrid would allow the existing overhead line to be decommissioned and the existing maintained corridor would return to a natural state."

The Mt. Sterling Sustainable Energy Project is subject to approval by the National Park Service as well as the North Carolina Utilities Commission.  If approved, implementation could occur in spring 2017.

More broadly, microgrids may be suitable alternatives to traditional transmission and distribution infrastructure.  Remote locations such as the Mt. Sterling radio site, where the cost of traditional grid power is either high or prohibitive, could be especially attractive candidates for microgrid development.  Infrastructure development in national parks can be controversial, even if the infrastructure in question is "green" or less intrusive than alternatives -- but microgrids may be particularly appealing if they can offer improved performance with reduced cost and environmental impacts.

FERC 2-year licensing pilot workshop

Tuesday, January 31, 2017

The regulatory process for Federal Energy Regulatory Commission licensing of hydropower projects can take many years and significant expense -- but can it be improved following a two-year pilot process ordered by Congress?  After running a pilot process for one license application, the Commission has scheduled a workshop to discuss lessons learned from its pilot licensing process.

Under the Federal Power Act, the Commission is responsible for licensing most non-federal hydropower development in the U.S.  Concerned over the duration and expense of the regulatory process, Congress enacted the Hydropower Regulatory Efficiency Act of 2013, section 6 of which directed the Commission to investigate the feasibility of a two-year licensing process, develop criteria for identifying projects that may be appropriate for the process, and develop and implement pilot projects to test the process.

After a January 6, 2014 solicitation for pilot projects, the Commission selected Free Flow Power Project 92, LLC's (FFP) proposed 5-megawatt project at the Kentucky River Authority's existing Lock & Dam No. 11 on the Kentucky River.  The January notice set minimum criteria and a process plan for projects that may be appropriate for licensing within a two-year process, including:
  • The project must cause little to no change to existing surface and groundwater flows and uses;
  • The project must not adversely affect federally listed threatened and endangered species;
  • If the project is proposed to be located at or use a federal dam, the request to use the two-year process must include a letter from the dam owner saying the plan is feasible;
  • If the project would use any public park, recreation area, or wildlife refuge, the request to use the two-year process must include a letter from the managing entity giving its approval to use the site; and
  • For a closed-loop pumped storage project, the project must not be continuously connected to a naturally flowing water feature.
After trying a two-year pilot to abbreviate its hydropower project licensing process, the Commission has scheduled a workshop to discuss the pilot's effectiveness.

Kitty Hawk NC offshore wind auction set

Thursday, January 26, 2017

U.S. plans to auction ocean sites off North Carolina for commercial offshore wind energy development advanced last week, as the federal Bureau of Ocean Energy Management scheduled a commercial lease sale for the sites for March 16, 2017.  But will the Trump administration continue the Obama administration's offshore wind leasing program?

Under federal law, the Bureau of Ocean Energy Management is charged with leasing sites on the Outer Continental Shelf for fossil fuel or renewable energy development.  To date, BOEM has held six competitive lease sales and has also awarded several leases on a non-competitive basis.

Up for auction on March 16 will be the rights to about 122,405 acres offshore Kitty Hawk, North Carolina.  The Kitty Hawk Wind Energy Area was first identified by BOEM in 2014, and was the subject of a Proposed Sale Notice last year.  As described in the Final Sale Notice for the Kitty Hawk offshore wind auction, the lease area is located about 24 nautical miles offshore. 

The Final Sale Notice for the Kitty Hawk lease area also identifies nine companies that BOEM has deemed legally, technically and financially qualified to participate in the upcoming lease sale:
  • Avangrid Renewables, LLC
  • Enbridge Holdings (Green Energy) LLC
  • Shell WindEnergy Inc.
  • Northland Power America Inc.
  • Wind Future LLC
  • Outer Banks Ocean Energy, LLC
  • PNE Wind USA, Inc.
  • Statoil Wind US LLC
  • wpd offshore Alpha LLC
The Kitty Hawk offshore wind site lease auction is scheduled to be held on March 16.  According to the National Renewable Energy Laboratory, the U.S. is home to an estimated 4,200 gigawatts of potential offshore wind capacity, with most potential located in federal waters.  Competitive lease sales by BOEM to date have yielded over $58 million in winning bids.  But it may be possible for the Trump administration to change direction with respect to policies affecting federal leasing of sites for commercial offshore wind development.  President Trump's "America First Energy Plan" does include a focus on increased production of domestic energy resources, although it singles out shale oil, gas, and coal (and does not mention offshore wind).  How will U.S. offshore wind fit into America's domestic energy strategy?

President Trump's America First Energy Plan

Tuesday, January 24, 2017

With U.S. President Trump now in office, a look at his "America First Energy Plan" suggests potential directions for his administration.


President Trump's energy strategy as posted on the White House website shortly after the inauguration describes energy as "an essential part of American life and a staple of the world economy."  The 7-paragraph document expresses the administration's commitment to policies that reduce consumer costs and "maximize the use of American resources."

Some elements of the Trump plan aim to reverse policies developed by the former Obama administration.  For example, the plan repeats campaign commitments to eliminate federal regulations and policies like the Climate Action Plan and Waters of the U.S. rule.

Other elements focus on domestic energy resources, including "shale oil and gas" and "clean coal technology."  The plan touts both U.S. economic development and national security benefits from increased domestic energy production.

The plan also addresses the nexus of energy and the environment, acknowledging that "our need for energy must go hand-in-hand with responsible stewardship of the environment."  It notes that "President Trump will refocus the EPA on its essential mission of protecting our air and water."

FERC electric storage policy statement

Monday, January 23, 2017

U.S. energy regulators have issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.  The Federal Energy Regulatory Commission's January 19, 2017 policy statement on storage provides insight into how the Commission views its role in regulating the rates at which energy storage would be compensated -- but was accompanied by a dissenting view expressed by Commissioner LaFleur.   The result is a mix of both greater certainty and continued debate.

Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid.  Today's electric storage resources can both charge and discharge electricity to and from the grid.  Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided.  In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution. 

Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates.  But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates.  Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.

This is a good thing, according to the Federal Energy Regulatory Commission.  According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."

But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently.  As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."

With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues.  It details possible approaches for avoiding double recovery of costs.  The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors."  The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.

Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions."  While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing."  In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams.  She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.

Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues.  Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions).  Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.

EPA FAQ on dam removal projects

Friday, January 6, 2017

The U.S. Environmental Protection Agency has released a document answering "Frequently Asked Questions" about the removal of obsolete dams

As noted by EPA, dams "provide important societal functions for drinking water supply, flood control, hydropower generation, and recreation."  EPA estimates that the U.S. is home to between 2,000,000 and 2,500,000 dams -- but that between 75% and 90% of these dams "no longer serve a functional purpose."  Given the expense of maintaining dams and their safety, and some negative social and environmental impacts of dams, there is some pressure to remove obsolete dams.  According to EPA, over 1,300 dams have been removed in the U.S. since the early 1900s, with over 60 removals in 2015 alone.

EPA framed its dam removal FAQ in this context, noting that its answers to these questions would support dam removal efforts.  The FAQ addresses 20 distinct topics, ranging from dams' impacts on water quality, permitting issues related to dam removal, and EPA-related funding that could be used to support dam removal.

For example, the FAQ discusses permitting under Section 404 of the Clean Water Act, including the use of individual permits or general permits, including Nationwide Permits.  The FAQ encourages project proponents to work closely with the Army Corps of Engineers regarding Section 404 permitting.  It describes how EPA would evaluate specific requirements for monitoring or testing, such as in the case of contaminated sediments behind the dam.  The FAQ also discusses other permitting requirements, such as state-issued water quality certifications pursuant to Section 401 of the Clean Water Act, and evaluations of consistency with coastal zone management plans under the Coastal Zone Management Act.

The FAQ also notes that various grants may be available for dam removal projects.  For example, grants under Section 319 of the Clean Water Act can be issued to states, territories, and tribes for dam removals.  EPA's Five Star Wetland and Urban Water Restoration Grant Program could also provide funding for river, wetlands, riparian, forest and coastal restoration, and wildlife conservation.  Other funding, such as under the Wetland Program Development Grant program, is available to build technical and programmatic capacity of state and tribal water agencies.  Finally, the FAQ notes that dam removals could be part of a Supplemental Environmental Project proposed in settlement of an environmental enforcement action.

As noted by EPA, the FAQs released in December 2016 do not impose legally binding requirements on anyone, and EPA retains the discretion to adopt approaches on a case-by-case basis that differ from those described in these FAQs where appropriate.  Nevertheless the document provides dam owners, regulators, and communities guidance on how EPA views dam removal proposals.