Maine regulators approve long-term contract

Maine utility regulators have approved a long-term contract to purchase the output of a 72.6-megawatt wind power project under development by Weaver Wind, LLC in Hancock County, Maine. The 20-year contract bears a price of 3.5 cents per kilowatt-hour, escalating at 2.5 percent per year.

A Maine statute enacted in 2006 authorizes the Public Utilities Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts, to the degree necessary to ensure reliability, meet energy efficiency program requirements, or reduce customer costs. In 2008, the Commission used this law to order a contract with the Rollins Wind project. After three subsequent procurement rounds, in 2017 the Commission approved a contract to buy 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years.

In response to its most recent solicitation, earlier this year the Commission approved a term sheet for a contract to buy 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years. Most recently, on July 12, 2019, the Commission approved a contract to buy the output of the Weaver Wind project, also at a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.

In addition to this existing law, in 2019 the Maine state legislature enacted several additional long-term contracting programs. One new law creates a new "Class IA" renewable portfolio standard, and requires the procurement by December 31, 2020 of energy or renewable energy credits from Class IA resources sufficient to cover between 7 and 10 percent of Maine's retail electricity sales, with a second round bringing the total procurement to 14 percent of Maine's retail electricity sales. Another new law requires the procurement of 375 megawatts from distributed generation resources between 2020 and 2024, with each project sized at less than 5 megawatts, and specific requirements for participation by non-residential and "community" or shared-ownership projects.

Collectively, these laws create a variety of opportunities for electric power generation projects to compete for and win long-term contracts to sell their output to Maine utilities.

FERC upholds Block Island offshore wind PPA

Federal energy regulators have denied a complaint by a Newport, Rhode Island city councilor against state regulators' approval of a power purchase agreement for an offshore wind project off Block Island.

At issue is Deepwater Wind Block Island, LLC's small-scale 30-megawatt offshore wind project located near Rhode Island's Block Island. The project sells its output to utility Narragansett Electric Company, Inc. d/b/a National Grid (National Grid), pursuant to a power purchase agreement approved by the Rhode Island Public Utilities Commission on August 16, 2010.

On June 7, 2018, Ms. Kathryn E. Leonard filed a complaint to the Federal Energy Regulatory Commission, alleging that the implementation of the power purchase agreement violated various federal laws, including the Federal Power Act, Public Utility Regulatory Policies Act of 1978 (PURPA), and the Supremacy and Interstate Commerce Clauses of the U.S. Constitution.

On April 24, 2019, the Commission issued its order denying Ms. Leonard's complaint. In the seventeen-page order, the Commission noted that the complainant provided no evidence in support of her assertion that the power purchase agreement was entered into pursuant to Rhode Island's implementation of PURPA. Instead, the Commission found that the Rhode Island Public Utilities Commission's approval of the contract was pursuant to state law, not pursuant to its PURPA regulations -- but that even if it were pursuant to PURPA, federal regulations governing sales by qualifying facilities to electric utilities explicitly permit negotiated rates.

The Commission similarly found that the complainant failed to show that the contract or its pricing was unjust and unreasonable under the Federal Power Act, and to provide sufficient support for its constitutional claims. The Commission also distinguished the Block Island PPA from contracts it previously invalidated in another case, Hughes v. Talen, which involved contracts for differences and an explicit requirement of participation in the capacity market. For these reasons, the Commission denied the complaint.

The Block Island project is the first commercially-operating offshore wind project in the United States. A number of other projects are currently under development, and several states in the Northeast have enacted laws requiring utility procurement of offshore wind energy. According to a 2016 analysis by the U.S. Department of Energy, U.S. offshore wind has a technical resource potential of more than 2,000 gigawatts of capacity, or 7,200 terawatt-hours of generation per year -- nearly twice the nation’s current electricity use.

2018 marks record for corporate renewable energy buys

According to Rocky Mountain Institute’s Business Renewables Center, corporate renewable energy procurement set a new single-year record for new capacity of announced wind and solar deals in 2018.

The Center reports that as of mid-December 2018, publicly announced corporate procurements of renewable energy reached 6.43 gigawatts. Procurement approaches counted toward this total include power purchase agreements, green power purchases, green tariffs, and outright project ownership in the United States.

Facebook, AT&T, Walmart, ExxonMobil and Microsoft had the five highest total volumes of newly announced deals; Facebook alone added 1,849.5 megawatts of new renewable procurement.

The Center notes that the U.S. renewables market has nearly doubled its annual total of corporate clean energy off-site deal volume since its prior highpoint in 2015. Also noteworthy is a near-doubling of the number of new entrants into the procurement market, including AT&T which completed deals for 820 megawatts of renewable power in 2018.

According to the Center's Deal Tracker, the total cumulative corporate procurement of renewable energy in the U.S. since 2013 now exceeds 15 gigawatts.

NJ approves offshore wind funding mechanism, rejects demonstration project

On December 18, the New Jersey Board of Public Utilities took two actions affecting offshore wind: approving the state’s Offshore Wind Renewable Energy Certificate (OREC) funding mechanism, but rejecting a petition by Nautilus Offshore Wind, LLC to install a 25 MW offshore wind demonstration project in state waters off the coast of Atlantic City. Meanwhile, developers have formed a new joint venture to develop offshore wind in federal waters farther offshore New Jersey.

New Jersey Governor Phil Murphy has set a goal of 3.5 gigawatts of offshore wind capacity by 2030, and in May 2018 he signed into law a renewable energy bill codifying that goal into statute. On September 17, 2018, the NJBPU opened the nation’s largest single-state solicitation to date, seeking 1,100 megawatts of offshore wind. Applications will be accepted through December 28, 2018. Winning projects will be compensated through the OREC mechanism approved this week, which requires electric companies to buy defined quantities of ORECs from offshore wind developers, much like a traditional renewable portfolio standard mechanism.

Also on December 18, the BPU rejected a 25 megawatt demonstration project proposed by Nautilus (under development by EDF Renewables and Fishermen’s Energy). The Nautilus project would feature three turbines in state waters about 2.8 miles offshore Atlantic City. But the BPU found the Nautilus project did not demonstrate the economic and environmental benefits required under the Offshore Wind Economic Development Act for the state to commit ratepayer funds. In particular, the BPU found that Nautilus didn’t provide sufficient information to substantiate claimed economic benefits, and further that Nautilus demanded a price that was too high given the unsubstantiated benefits.

But offshore wind development may soon occur farther offshore New Jersey. On December 19, 2018, EDF Renewables North America and Shell New Energies US LLC announced the formation of a 50/50 joint venture, Atlantic Shores Offshore Wind, LLC to co-develop offshore wind generation in federal waters offshore New Jersey. The site is about 8 miles offshore Atlantic City. At issue is the 183,353-acrea OCS-0499 lease area, the rights to which were initially auctioned by the federal Bureau of Ocean Energy Management in 2015. That auction was won by Toto Holding Group subsidiary US Wind Inc., with a winning bid of $1,006,240.

More recent federal auctions for offshore wind site leasing rights have brought much higher winning bids -- for example, a December 2018 auction for sites offshore Massachusetts brought in about $135 million for each of three lease areas, totaling over $405 million in winning bids for about 390,000 acres.

Will Utah counties fund thorium reactor?

Could a coalition of rural counties in Utah and a startup company develop a thorium-fueled nuclear reactor for electric power and other purposes?

According to its website, the Seven County Infrastructure Coalition is currently comprised of seven counties in eastern Utah: Carbon, Daggett, Duchesne, Emery, San Juan, Sevier, and Uintah.  The website describes the Coalition’s main roles and mission as "to identify revenue-producing infrastructure assets that will benefit the region" and "to plan infrastructure corridors, procure funding, permit, design, secure rights-of-way and own such facilities," with operation and maintenance possibly outsourced to third parties.

Apparently under consideration by the Coalition are energy projects, including a "thorium energy" project and a "hydrogen plant" project.  For example, the "Procurement" section of the Coalition's website includes a Request for Qualifications for Project Analyst for Potential Thorium Energy and Hydrogen Plant Projects, as well as a Request for Qualifications Project Financial Analyst on Potential Thorium Energy Project.

Under the Project Analyst RFQ, which closed August 1, 2017,

The Coalition seeks an individual or team to act as a Project Analyst to advise it and its member counties on two proposed projects, how to evaluate emerging technologies, and the respective project teams. One project is a thorium energy facility for producing electricity, etc. as proposed by Alpha Tech Research Corporation. The second project consists of hydrogen plants to be used as fueling stations for hydrogen/electric semi-trucks as proposed by Nikola Motor Company, LLC.

Responsibilities defined in this original RFQ would include evaluation of the thorium energy and hydrogen plant projects, including an evaluation of "the feasibility and viability of projects in general, as well as the proposed projects, and determine how the Coalition and its members may use their assets to best benefit the public."

According to its website, Alpha Tech Research Corp.'s motto is "Changing the face of nuclear power with clean, safe, molten salt reactor technology."  But little other public information is easy to find on the company.

Thorium is a radioactive element that can be used in a nuclear reactor as a fuel for power production.  It is distinct from the uranium-based fuel used in traditional nuclear power plants.  Some limited research and development was conducted on thorium-based reactors in the twentieth century, but recent projects and all commercial reactors rely the uranium fuel cycle.  Proponents of thorium reactors suggest abundant fuel supplies and reduced weapons proliferation risk compared to uranium, combined with other advantages of nuclear power such as reliable baseload generation with zero carbon emissions.  Some point to Utah's mineral richness as a cost-effective source for lithium, beryllium, and other materials that could be useful in molten salt reactor resign. But crucially the technology, regulation, and business structures necessary to support a thorium reactor may not yet exist.

Fifteen days after the Project Analyst RFQ closed, the Coalition issued another request for qualifications "to seek an individual or team to act as a Project Analyst to advise it and its member counties on a proposed project related to thorium energy. In addition, the Coalition seeks guidance on how to evaluate emerging technologies, and companies or groups proposing projects to the Coalition. The thorium energy facility for producing electricity, etc. is proposed by Alpha Tech Research Corporation." Proposals under this subsequent RFQ are due by 2:00 PM on October 2, 2017.  According to the Salt Lake Tribune, a coalition representative reported, "The coalition’s initial request for qualifications drew no adequate responses by its Aug. 1 deadline."  (Query why not.)

It's unclear how far the Utah counties' efforts can go.  The coalition's stated criteria for evaluating potential projects include requiring appropriate project benefits (such as facilitating needs in rural Utah that would otherwise go unaddressed), as well as avoidance of any "fatal flaws" (such as "obvious non-Coalition sponsor that should take the lead", project success unlikely" and "low perceived benefit compared to cost.")  The coalition is presumably at the stage where it is seeking expert advice to help it evaluate the thorium energy project under these criteria.

In its materials, the coalition emphasizes its expectation to rely on public-private partnerships, in part to allocate project risk to private entities with special expertise in taking those risks.  But developing the first commercial thorium reactor inherently involves a variety of risks -- including developing a technology that works, securing all necessary regulatory approvals, and having business or financial arrangements in place that make the project a success.  These risks could pan out in the counties' favor -- but might not.  A coalition of South Carolina utilities developing what would have been the nation's first new commercial nuclear reactor recently announced a decision to suspend that project partway through construction, following years of delay, billions of dollars in cost overruns.  While a thorium reactor might avoid some of these challenges, others are likely systemic to the state of the nuclear power industry from a technological, regulatory, and business perspective, and would be hard for the counties to avoid. The counties may also have more proximate opportunities to achieve similar goals, including by facilitating or developing renewable energy infrastructure.

At the same time, the coalition deserves credit for thinking proactively and considering its options.  Whether the coalition continues to pursue thorium energy, or focuses on less speculative projects, the coalition's fundamental mission remains "to improve the quality of life through cooperative regional planning, increased economic opportunity, and sustainable implementation."  With the right balance of risk and reward, its evaluation of proposed projects could advance that mission.

Massachusetts offshore wind RFP

Massachusetts' investor-owned electric distribution companies have issued a joint Request for Proposals for offshore wind energy projects.  Through the RFP, the utilities seek proposals for 400 megawatts (or more) of qualifying offshore wind energy generation and associated transmission, with winning bidders earning 15- to 20-year long-term contracts to sell project power.   This Massachusetts offshore wind RFP is designed as the first step in a staggered procurement schedule for compliance with a 2016 state law requiring the utilities to contract for 1,600 MW of aggregate nameplate capacity of offshore renewable generation by June 30, 2027.

In 2016, the Massachusetts legislature enacted the Energy Diversity Act, adding a new Section 83C to the Green Communities Act.  Section 83C provides in relevant part, "In order to facilitate the financing of offshore wind energy generation resources in the commonwealth, not later than June 30, 2017, every distribution company shall jointly and competitively solicit proposals for offshore wind energy generation; and, provided, that reasonable proposals have been received, shall enter into cost-effective long-term contracts."

The pending RFP is the first joint solicitation under Section 83C.   Through the RFP, the distribution companies are seeking to procure a total of approximately 400 MW of Offshore Wind Energy Generation.  The RFP defines this term as:

offshore electric generating resources derived from wind that: (1) are Class I renewable energy generating sources, as defined in Section 11F of Chapter 25A of the General Laws; (2) have a commercial operations date on or after January 1, 2018, that has been verified by the Department of Energy Resources; and (3) operate in a designated wind energy area for which an initial federal lease was issued on a competitive basis after January 1, 2012.

Bids are due by noon EDT on December 20, 2017.  The RFP prescribes a three-stage review process, including an initial eligibility and threshold screening, subsequent qualitative and quantitative review, and finally "further evaluation of remaining proposals to ensure selection of viable projects that provide cost -effective, reliable Offshore Wind Energy Generation with limited risk."

Pursuant to the Department of Public Utilities order approving the solicitation process, projects will be selected for negotiation by April 23, 2018, with contracts submitted for Department approval no later than July 31, 2018.

NY energy storage bill would launch program

The New York legislature has unanimously passed a bill establishing an energy storage deployment program.  The bill, S. 5190, aims to promote the installation of energy storage systems.  The bill now awaits Governor Andrew Cuomo's signature, before it can take effect.

New York is in the midst of major shifts in its energy policy.  Governor Cuomo's "Reforming the Energy Vision" or REV process aims to build a clean, more resilient, and affordable energy system for all New Yorkers.  As part of that process, last year, the Public Service Commission adopted a Clean Energy Standard which requires 50% of New York’s electricity to be generated by renewable sources by 2030, and provides support for 3 nuclear power plants considered at risk of closing.  Meanwhile, the state is also reforming the way energy service companies, or retail electric suppliers, market their services.

In adopting renewable energy procurement mandates as part of the Clean Energy Standard in 2016, the Commission also considered creating specific mandates for energy storage.  As noted in the order adopting the Clean Energy Standard, "Storage is a critically important component of the energy system that is both distributed and increasingly reliant on intermittent resources. Unlike other resources, the load shifting and fast response capabilities of various forms of storage resources allow them to provide simultaneous value as an energy and reliability resource. Storage can also provide value to the distribution based retail and bulk power markets... In short, it is without question that modern markets must sufficiently and accurately value storage as a vehicle to design and optimize network planning and operations."

But in that order, the Commission concluded that "as a reliability support and system optimizing resource, storage is not properly characterized as a standalone renewable energy resource under the CES. That being said, if the various mechanisms that the Commission is pursuing to ensure storage takes it rightful place as a critical resource for the modern grid prove insufficient, this topic will be revisited."

S. 5190 would change New York's position, by requiring that the Commission establish 2030 targets for the installation of qualified energy storage systems.  It defines a qualified system as technology using mechanical, chemical, or thermal processes to absorb, store, and dispatch energy generated from renewable resources or mechanical processes.  The bill's official justification statement cites the increased use of intermittent renewable energy sources, such as solar and wind, in an effort to combat climate change, and the efficiency of using energy storage systems to solve issues relating to changes in how energy supply and demand align in time.

Three other states -- Massachusetts, California, and Oregon -- have adopted energy storage procurement policies, and the Federal Energy Regulatory Commission is exploring how electric storage resources can be integrated into wholesale and regulated markets.

Maine community solar procurement bill, LD 1444

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.

Massachusetts energy storage report

A Massachusetts state energy office has issued a report finding that Massachusetts has the potential to develop for 600 MW of energy storage by 2025, which could lower costs, reduce carbon emissions, and improve grid reliability. Legislation earlier this year authorized the creation of an energy storage procurement target; the Department of Energy Resource’s State of Charge report could lead to further policy changes supportive of storage.

While electricity has traditionally been challenging to store efficiently, advanced energy storage technologies – such as batteries, flywheels, thermal and compressed air technologies – now allow utilities and consumers to store and release energy as needed. Last year, the Baker-Polito administration launched an Energy Storage Initiative to advance the energy storage segment of the Massachusetts clean energy industry.

This summer, the Massachusetts legislature enacted a broad energy diversification law, authorizing among other things the creation of an energy storage procurement target, if the Department of Energy Resources deems such a target prudent.  Section 15 of H.4568 requires the Department of Energy Resources to determine, by December 31, 2016, whether to set “appropriate targets for electric companies to procure viable and cost-effective energy storage systems” to be achieved by January 1, 2020. If the Department finds it appropriate to adopt procurement targets, the law requires it to do so by July 1, 2017, with reevaluations of the procurement targets not less than every 3 years.

Meanwhile, on September 16, 2016, the administration released its State of Charge report. The report found that energy storage could yield significant cost savings for Massachusetts ratepayers, reduce the impacts of peak demand on the state’s energy infrastructure, and enable improved integration of renewable resources and reduced carbon emissions.

The report recommends policy changes, ranging from regional coordination on energy storage, broadening the Alternative Portfolio Standard (APS) with respect to advanced energy storage, to using energy storage in existing energy efficiency programs or as a utility grid modernization asset, and seeking “renewables plus storage” contracts in future long-term clean energy procurements.

According to the report, adopting these recommendations could yield 600 MW of advanced energy storage technologies deployed on the Massachusetts grid by 2025, with projected ratepayer cost savings of over $800 million and approximately 350,000 metric tons reduction in greenhouse emissions over a 10 year time span.

The Department of Energy Resources will now hold a stakeholder engagement process relating to energy storage, starting with a meeting scheduled for September 27. DOER is expected to determine whether Massachusetts should establish an energy storage procurement target before the end of 2016.

Offshore wind in Massachusetts energy bill

The Massachusetts legislature has enacted an energy bill that will require utilities to purchase offshore wind energy by 2027.  The legislation, known as H. 4568, "An Act to promote energy diversity," has been laid before Governor Charlie Baker for signature.

Earlier this session, the Massachusetts House and Senate had passed two different bills calling for renewable energy procurement.  A conference committee reported out the final bill, H. 4568, on July 31.  Through the newly enacted law, the Massachusetts legislature has added a new program of offshore wind energy procurement. 

The final enacted bill adds a new section 83C to the state's 2008 Green Communities Act.  Among other provisions, section 83C provides, "In order to facilitate the financing of offshore wind energy generation resources in the commonwealth, not later than June 30, 2017, every distribution company shall jointly and competitively solicit proposals for offshore wind energy generation; and, provided, that reasonable proposals have been received, shall enter into cost-effective long-term contracts."

Much of the solicitation and contracting process will occur pursuant to regulations yet to be promulgated by the Department of Public Utilities.  The law provides a framework for developing and approving the competitive bidding process, and requires the schedule to "ensure that the distribution companies enter into cost-effective long-term contracts for offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027."  Individual solicitations must be seek proposals for 400 megawatts or more, and may be conducted jointly with other states.

Proposed long-term contracts are subject to the review and approval of the Department of Public Utilities.  The law requires the department of public utilities to weigh the potential costs and benefits of the proposed long-term contract, and directs it to approve a proposed long-term contract "if the department finds that the proposed contract is a cost-effective mechanism for procuring reliable renewable energy on a long-term basis," taking into account factors like reliability, mitigation of price volatility, cost-effectiveness, mitigation of environmental impacts, and economic development.

The law requires the implementing regulations to be adopted by the Department of Public Utilities to "provide for an annual remuneration for the contracting distribution company up to 2.75 per cent of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract."  It also entitles distribution companies to cost recovery of payments made under an approved long-term contract.  Utilities may elect to to use any energy purchased under such contracts for sale to its customers and retain renewable energy certificates for their use, or may sell the energy and RECs into the market.  Any proceeds from such market re-sales will be netted against the cost of contract payments, resulting in a credit or charge to all distribution customers through a uniform fully reconciling annual factor in distribution rates.

The law also provides a variety of "outs" or circumstances under which contracts might not result, such as if a "proposal’s terms and conditions would require the contract obligation to place an unreasonable burden" on a distribution company’s balance sheet.

Notably, the law's definitions of “Offshore wind developer” and “Offshore wind energy generation” place a variety of restrictions on projects eligible for contracting.  The definitions effectively require that projects be located on the Outer Continental Shelf, in a designated wind energy area for which an initial federal lease was issued on a competitive basis after January 1, 2012, have no turbine located within 10 miles of any inhabited area, and have a commercial operations date on or after January 1, 2018, that has been verified by the department of energy resources.  This effectively limits projects to a subset of those winning recent (or future) federal Bureau of Ocean Energy Management lease auction sales.

To date, no commercial offshore wind projects operate in U.S. waters, although Deepwater Wind is currently constructing the Block Island Wind Farm off Rhode Island.   Federal programs, along with some state incentives, are available to support qualifying offshore wind projects.

Maine biomass procurement competitive standards

As the Maine Public Utilities Commission prepares for its upcoming procurement of biomass power resources, the Commission has requested public comment on the standards and criteria to be used in evaluating whether the solicitation is "not competitive."

This spring, the Maine State Legislature enacted An Act To Establish a Process for the Procurement of Biomass Resources.  The law directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable, seeking proposals for 2-year contracts for up to 80 megawatts of biomass resources.  

But largely due to fairness and cost-containment concerns, the legislature created a "safety valve" in case the solicitation turns out to be "not competitive."  The Act specifies that “If the commission concludes that the solicitation ... is not competitive, no bidders may be selected and the commission is not obligated to enter into a contract.”

On May 17, 2016, the Commission issued a request for comment in its Procurement of Biomass Resources docket.  That request describes the Commission's plans to initiate the procurement process "in the near future" through the issuance of a request for proposals or RFP.  But before issuing the RFP, the Commission has requested comment on the standards and criteria to be used to determine whether the solicitation is “not competitive” pursuant to the Act.

Comments are requested by May 30, 2016.

Maine Green Power offer provider selected

Maine energy regulators have chosen a manager for the Maine Green Power program.  In an April 4, 2016 order, the Maine Public Utilities Commission selected 3Degrees Group, Inc. to manage the program.  3Degrees has operated the program since its 2013 launch, and now has the Commission's approval to run the program for another five-year term, with some changes to pricing, renewable energy certificate procurement, and risk mitigation procedures.

Maine's green power offer was established by a 2009 Maine law requiring the Commission to arrange for a green power offer -- a fully renewable competitive electricity supply option -- and to ensure its availability to residential and small commercial electricity customers.  Following a 2010 RFP, the Commission selected 3Degrees, Inc. to provide the first round green power offer.  Its program, named Maine Green Power, was officially launched in April 2013.  It featured blocks of 500 kilowatt-hours per month of renewable energy.  Its existing term of service expired on March 31, 2016.

Legislation enacted in 2015 extended the green power program's sunset date to April 1, 2021. On November 12, 2015, the Commission solicited proposals from providers to manage the program for a five-year term beginning on April 1, 2016.  According to the April 4, 2016 order selecting 3Degrees, the Commission evaluated proposals "based on cost considerations, non-cost aspects such as supplier experience, customer sign-up ease, and the potential use of renewable energy credits (RECs) from community-based renewable energy projects."

The Commission found "that the proposal submitted by 3Degrees, Inc. best suits the needs of the green power program."  According to the order, that proposal maintained the 500 kWh block structure, with a 19% increase in pricing.  3Degrees also proposed separate commercial pricing that includes a reduction in the per kWh price for higher usage.

The Commission also approved changes to the program's REC procurement and risk mitigation processes "in light of the five-year contract and the potential volatility in REC prices in future years":

Because of significant concerns about the price of Maine RECs in the next five years, particularly Maine Class I RECs, 3Degrees has proposed that it shall be required to use no less than $5.50 per REC of revenues paid by program participants for REC procurement purposes, as calculated as an average over the most recent three year period. At the proposed pricing for a residential customer of $8.95 for a 500 kWh block of green power, a customer would pay $17.90 for one REC. The 3Degrees proposal would require that no less than $5.50, or approximately 30%, of the funds paid by customers be spent directly on procuring RECs for the program.

The order also approved a risk mitigation mechanism.  If the procurement cost of Maine-based RECs exceeds $6.50 per REC on average (including Class I and Class II), 3Degrees could procure RECs from resources elsewhere in New England, or even from outside New England with Commission approval.  But because the program is promoted as Maine-based, the Commission directed 3Degrees to develop appropriate consumer education materials to explain the potential that, under certain circumstances, RECs may be sourced from outside of Maine or even the New England market.

Maine solar legislation released

The Maine legislature has printed a bill whose enactment would reshape the state's solar energy laws.  The bill, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development, has been numbered as LD 1649.  It would replace a billing treatment called net metering with a series of long-term contracts and utility procurement orders.

Solar photovoltaic panels on the roof of Gallagher's Auto Parts, in Patten, Maine.

Under net metering or “net energy billing,” an electric utility invoices a customer with solar panels based on the difference between the customer's energy use and the solar project's output.  If the generator output exceeds monthly usage in any billing period, the customer earns kilowatt-hour credits that can be banked and netted against future usage.  The bipartisan non-governmental organization National Conference of State Legislatures has noted that "Net metering policies have facilitated the expansion of renewable energy through on-site generation, also known as distributed generation."

But a 2015 Maine legislative resolve directed the Public Utilities Commission to convene a stakeholder group to consider alternatives to net energy billing, largely in the hopes of helping more consumers connect with solar power.  As part of that case, the state's Office of Public Advocate proposed a structure where individual solar projects would enter into contracts to sell solar power to their local utility.  While stakeholders developed consensus around exploring the concept, there was not uniform agreement around whether it should immediately replace net metering, or whether the new concept should operate "side by side" with net metering for some test period.

The bill now printed as LD 1649 largely reflects the contract-based, solar standard buyer proposal.  It would direct the Public Utilities Commission to enter into twenty-year contracts for the procurement of 248 megawatts of solar energy between 2017 and 2022.  The bill allocates 60 megawatts (24%) to grid-scale solar distributed generation resources; 45 megawatts (19%) to large-scale community solar resources; 25 megawatts (10%) to commercial and industrial resources; and 118 (47%) megawatts to residential and small business resources.  This would represent a significant expansion of solar capacity in Maine compared to what has been developed to date.

Under LD 1649, customers could seek contracts to sell solar power to a standard buyer (the utility) at prices set by the Public Utilities Commission. The standard buyer's stated role is to purchase the output of these distributed generation resources, aggregate the portfolio of resources procured, and sell it into the relevant New England markets. 

Consumers with projects up to 250 kilowatts in capacity could have two options.  The first is to sell the project's entire output to the utility under a contract, and buy all the customer's electricity requirements back from the utility in a separate transaction.  This is sometimes described as a "buy-all, sell-all" structure.

The second option is to use onsite generation to first offset electric consumption, and sell any excess electricity.  This would allow hourly offsetting of onsite load, but would not allow customers to carry forward monthly credits for excess production that could be used to offset future load.  This differs from net metering under Maine's current regulations, which measure net energy use over an entire month billing period, and carry credits forward for up to 12 billing months.

This contracting structure would effectively replace net metering. No new customers could participate in net metering once the new rules take effect.  Those residential and small business customers who already net meter their loads against a distributed solar project would face a choice: either seek a long-term contract under the new program, or elect to net meter for 12 more years.    

The bill would also largely eliminate Maine's policy of virtual net metering, which has allowed customers to net meter load at one site against a solar project located elsewhere in the same utility's service territory.

As of late on March 9, LD 1649, An Act To Modernize Maine's Solar Power Policy and Encourage Economic Development, had not yet been referred to committee, nor a public hearing scheduled.

Navy signs solar energy deal

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?

Maine PUC declines to OK Statoil offshore wind term sheet

Today the Maine Public Utilities Commission declined to approve a term sheet offered by Statoil North America, Inc. for a long-term power purchase agreement from its proposed Hywind Maine floating offshore wind project.

Sutton Island, Maine, about 80 miles downeast of the proposed Hywind Maine project.

In 2010, Maine enacted a law designed to support the development of offshore wind and other marine renewable energy projects.  Among other features, that law required the state Public Utilities Commission to conduct a competitive solicitation for proposals for deep-water offshore wind energy pilot projects, meaning grid-tied floating wind projects at least 10 nautical miles offshore.  The statute gave the commission authority to direct mainland utilities to enter into power purchase agreements with one or more responding developers if certain minimum criteria were met.  This authority was discretionary, meaning the commission could choose not to order the utilities to sign a deal even if it met those criteria.

In September 2010, the commission issued its request for proposals under the program. Over the ensuing years, Statoil emerged as the apparent leading respondent, proposing the "Hywind Maine" project, a four-turbine, twelve megawatt project south of Boothbay Harbor.  Commission staff and Statoil negotiated the terms of a proposed power purchase agreement, which became public this summer.  Among those terms was a proposed energy price of between $290 and $320 per megawatt-hour, escalating annually, for the first 41 gigawatt-hours of energy produced each year.

That term sheet was the subject of deliberations by the Maine commission this morning.  After two hours of discussion, two of the three commissioners had stated that they would vote against approving the term sheet.  They expressed concerns about the cost of the contract, as well as uncertainty over the deal's benefit to Maine and Maine ratepayers.

The Maine commission's action bears some resemblance to that of the Rhode Island Public Utilities Commission in 2010 when it rejected a proposed contract between utility National Grid and offshore wind developer Deepwater Wind on the grounds that $244 per megawatt-hour was not a "commercially reasonable" price.  The Rhode Island commission ultimately approved a renegotiated deal with Deepwater Wind at a comparable price.  Similarly, the Maine commission invited Statoil to revise its proposal to offer more benefits to Maine, and to present a renegotiated deal for further deliberation.  Will Statoil be able to sweeten its offer and convince the commission that its contract is a good deal for Maine?