RenewNewEngland.com

New Rhode Island law resolves state renewable energy disputes

On Friday, Rhode Island Governor Donald Carcieri signed into law a bill that will require National Grid to enter into long term contracts for renewable energy.  Rhode Island is the latest New England state to supplement its renewable portfolio standard with a long term contract requirement. The law also includes rules tailored to bring Deepwater Wind's proposed offshore wind farm closer to fruition.

The law requires National Grid, the state's distribution company, to solicit and enter into ten to fifteen year energy contracts for 90 MW of new renewable generation located in Rhode Island, of which at least three MW must be solar photovoltaic.  The company has four years to enter into these contracts, which are subject to approval by the state Public Utility Commission. The law also lays out the procedure for a separate Commission proceeding to require National Grid to enter into long term contracts for energy from a "utility scale offshore wind farm" of up to 150 MW.  In both cases, National Grid received authority to charge an additional 2.75% bonus from ratepayers on sale of the electricity from the renewable sources.

The law resolves two thorny issues involving the state, National Grid, and renewable energy development in Rhode Island. The first involves National Grid's electricity supply.  In March, the PUC rejected National Grid's 2010 electricty supply plan for lacking any long term contracts for renewable energy sources, a ruling the utility appealed to the Supreme Court.  Both sides blinked: the PUC backed off its requirement, and National Grid withdrew its appeal.  The new law appears to resolve the dispute, though some PUC commissioners have expressed displeasure, particularly with the incentive rate.  The second involves a proposed offshore wind farm that could bring the state as many as 800 new jobs. Last September, Rhode Island selected Deepwater Wind to build a 150 MW, $1.5 billion wind farm off the coast of Rhode Island.  The developers had been unable to find a buyer to commit to purchasing power from the massive project, which made the project impossible to finance.  By guaranteeing a purchaser for the power, the new law enables the developers to move forward with the permitting process. 

On that front, this week the Department of Interior issued its first exploratory leases for offshore wind projects, the result of a compromise with FERC we've discussed previously.  Offshore wind in the US may soon be a reality.

Counting Hydro Out?

In an earlier post, we mentioned that a recent FERC decision had Canadian hydro developers cheering the agency’s characterization of hydro as clean energy.  Hydro is an important energy source in New England, but its treatment as a renewable energy source has never been uniform.  Each New England state currently allows hydro to count toward its Renewable Portfolio Standard (RPS), but no two state standards (pdf) in the region are alike.  To get a sense of the variation of treatment, just look at the variety of hydro plant size requirements for plants to qualify for each state’s RPS:  CT limits qualifying hydro to 5 MW or less (2003 or newer); Maine existing plants less than 100 MW; Massachusetts up to 25 MW (1997 or newer) (for Class I; Class II must be 5MW or less); New Hampshire counts incremental production for existing plants of any size (Class I) or new installations of 5 MW or less (Class IV); RI limits capacity to 30 MW; VT limits capacity to 200 MW.

This variety of state RPS standards will no longer be an issue if a national standard is enacted.  Which begs the question:  how will hydropower count under a national standard?  Under the current draft of the Waxman-Markey American Clean Energy and Security Act of 2009 (pdf) (the ACES Act), hydropower that qualifies for renewable certification is limited to:

• Incremental hydropower (improvements to the capacity or efficiency of existing hydro plants);
• Certain hydropower development at existing, non-generating dams; and
• Hydrokinetic technologies, such as ocean, wave and tidal generation. 

As with nuclear generation and generation utilizing carbon sequestration technology, non-qualifying hydro power is not certified as “renewable” under the current draft legislation, but is excluded from the calculation of a supplier’s base emissions. 

In short, when it comes to certifying renewable energy credits, conventional hydropower often doesn’t qualify, in spite of the fact that hydropower enjoys a substantial (and well-established) emissions advantage over other conventional power sources.  (For a discussion of the policy objectives RPSs are used to advance, see this previous post.)  We’ll be watching to see whether the certification of conventional hydro is the subject of debate when the ACES Act heads to floor.  But whether certification of hydropower is debated or not, hydro also serves as a sort of marker for the political debate that proposed legislation will surely face:  regions with significant hydro resources, like New England, have lower per-capita emissions and are more supportive of carbon legislation, while regions without hydro are more dependent on coal and much less likely to support the ACES Act.  This problem of regional inequality of carbon impact, has been explored in depth in a recent report (pdf) by the Brattle Group.  The report identifies a core of legislators – dubbed The Carbon Nine – who may need to be convinced that their constituents will not bear a greater burden under the ACES Act than those who, like New Englanders, already rely on low-emissions sources like hydro. 

Cashing in on the ARRA: the Investment Tax Credit Cash Grant Program

One of the hot topics at last week's Renewable Energy Project Finance Seminar Pierce Atwood co-sponsored with the Environmental Business Council of New England was the Investment Tax Credit (ITC) Cash Grant program created by the American Recovery and Reinvestment Act (ARRA).  The ITC cash grant is one of the most anticipated renewable energy incentives included in the ARRA.  In short, it transforms the 30% investment tax credit (for which wind, biomass, marine and other renewable facilities are now eligible) into a cash payment from the Treasury Department.  The grant must be paid within 60 days of the later of receipt of the application by the Treasury or the facility's in-service date.  (For a recap of the changes to the renewable energy tax incentives introduced by the ARRA, check out this previous post.)

The cash grant program was intended to jump-start renewable energy project development after the collapse of the financial industry sharply reduced demand for the tax credits developers relied on to finance their projects.  In the short term it has had the opposite effect.  The Treasury Department's delay in issuing rules for the new program is part of a larger stimulus-induced slowdown, as developers wait to take advantage of the full range of incentives made available under the ARRA.  One of the main reasons for the delay is Treasury's deep concern about the potential for fraud in the new program.

The switch from a tax credit based on the power output of a facility to the cost of construction dramatically changes the incentives for a renewable energy developer.  Likely gone, for example, are the detailed siting and wind studies needed to ensure new wind facilities will generate and sell sufficient energy to generate the promised tax credits, since the ITC is not tied to the sale of energy.  Unlike other ARRA renewable energy tax incentives, there is no cap on the size of individual grants or the total amount of grants to be issued, so there may be a temptation to pad the costs of the facility with fraudulent expenses and collect a larger cash grant.  And unlike the ITC or the Production Tax Credit, the grants are not claimed as part of a tax filing, and the Treasury Department has indicated that it does not intend to audit grant recipients.

The concerns may be overstated: the grants likely remain subject to the reporting requirements and penalties of the Recovery Act itself, and any fraudulent applications would be subject to the treble damages and qui tam enforcement provisions of the civil False Claims Act.  And ultimately, any problem is relatively short lived: only facilities that enter service in 2009 or 2010, or begin construction in those years and are completed by 2017, are eligible for the grant.  Right now, the primary concern is getting the money out the door, so that the stimulus act will have its intended effect on the renewable energy industry.

"An Act Regarding Maine's Energy Future" is Law

Responding to volatility in home heating energy prices and anticipating the passage of the American Reinvestment and Recovery Act, in January, 2009 the Legislature established (pdf) the Joint Select Committee on Maine’s Energy Future to undertake a holistic assessment of diverse energy issues.  In an effort to design a comprehensive process by which energy-related funds are allocated by the State, the 17-member Committee conducted a review of Maine's current approach to energy planning and received testimony from an array of stakeholders.

Today, Governor Baldacci signed the resulting legislation, LD 1485 (pdf), An Act Regarding Maine's Energy Future, into law.  The new law is the culmination of six months of effort by the Select Committee; highlights include:

• Consolidation of various conservation and energy efficiency programs, including electrical, natural gas, and greenhouse gas, into a newly established Efficiency Maine Trust, which will oversee the creation, planning and implementation of energy efficiency and alternative energy resource programs;
• Articulation of efficiency, emissions and consumptions goals intended to reduce Maine's usage of foreign fuels;
• Creation of the Maine Energy, Housing and Economic Recovery Program to be run by the Maine State Housing Authority, which establishes funding sources for affordable housing;
• Establishment of a legislative Commission to study efficiency infrastructure, especially energy corridors, cables, pipelines, and other structures, with Commission recommendations due by December 2, 2009; and
• Placement of a moratorium until mid-2010 on the final permitting of certain energy corridors and facilities, pending any legislative recommendations.

The new law is effective immediately in order to allow the Governor to start the appointment process for the members of the newly established nine-person Board which will oversee the new Trust.  The Trust in turn will commence its duties and activities starting July 1, 2010.

Several members of the Pierce Atwood Energy Practice Group were actively involved with the creation of the new law, and specific questions regarding LD 1485 should be directed to Pattie Aho. 

Like Water to DC

In a recent decision (pdf), the FERC granted preliminary approval to a single transmission line, proposed by Hydro-Quebec, NStar and NE Utilities.  The line will be a high-voltage direct current (DC) line, bringing 1,200 MW of hydropower from Canada to the ISO-New England region via a southern New Hampshire tie-in.  The project is proposed as a participant-funded project, meaning the proposal does not seek to socialize the costs among the ISO-New England states.  Instead, the project will essentially be funded by a long-term contract for the energy it’s designed to transmit. 

Canadian officials cheered this decision by the FERC; in their view, this is the first FERC approval of a major long-term contract for Canadian hydropower since the 1980s and marks the first time hydro power has been acknowledged by a federal agency as a clean source of power.  Canadian hydropower developers – on both coasts – are cheering these developments, too, concluding that Canadian hydropower will now be a welcome player under the Obama Administration’s energy policy. 

But south of the border, several developers of smaller renewable projects in northern New Hampshire claim the Hydro-Quebec transmission project will have a chilling effect.  These wind and biomass projects face a host of technical, regulatory and financial hurdles, but they also require transmission upgrades in order to be viable, and interconnection with the Hydro-Quebec line is not an option.  The Hydro-Quebec line would be a high-powered direct current line, requiring expensive transformers to change it into alternating current that goes to people’s homes.  Developers in New Hampshire worry that the massive Hydro-Quebec line would make improvements to the existing transmission system seem unnecessary to NH officials and ISO-New England, and they can’t afford the upgrades without socializing the costs or receiving financial support from the state. 

Vermont Enacts Feed-In Tariff Program

On May 27, 2009, the Vermont Energy Act of 2009 (pdf) became law, taking effect without Governor Douglas’s signature.  The law implements a pilot feed-in tariff program designed to encourage the development of renewable energy in the state.

The new legislation sets minimum rates for the purchase of electricity from qualifying renewable energy sources with a plant capacity of 2.2 megawatts or less that are commissioned on or after September 30, 2009.  Retail electricity providers in Vermont are required to purchase electricity from these sources under long-term, fixed contracts of 10-20 years, or 10-25 years in the case of solar energy sources.  The electricity purchased and any associated costs are distributed to retail electricity providers based on their pro rata share of Vermont’s total retail electricity sales for the previous year. These contracts will be available until the cumulative plant capacity for all such sources in the state reaches 50 megawatts.    

The legislation sets initial rates for electricity purchased under the program, based on the type of renewable energy technology and the size of the project.  For wind energy projects less than 15 kW, initial tariffs are set at $0.20/kWh; for landfill and biogas, $0.12/kWh; and for solar, $0.30/kWh.  For wind projects greater than 15 kW, hydropower, or other biomass, initial tariffs are set according to a formula based on the state’s average residential electricity rate. Retail electricity providers and renewable energy facility owners may also elect to enter into alternative arrangements.

Although the legislation sets initial tariffs, it directs the Vermont Public Service Board to reexamine those rates beginning in September 2009 and set new rates by January 15, 2010, and to review those rates every two years thereafter.  The Board is directed to calculate rates by considering the costs of each type of renewable energy technology, and including profits based on the rate of return received by Vermont’s retail electricity providers.  The Board may then make adjustments needed to ensure sufficient incentives for renewable energy development.

This post was contributed by Carol Garvan, summer associate at Pierce Atwood LLP.

Maine PUC Begins Inquiry Into Decoupling

On May 20th, the Maine Public Utility Commission issued a Notice of Inquiry"to obtain information and viewpoints regarding whether there is a need to provide different or additional financial incentives to the State’s transmission and distribution (T&D) and natural gas utilities to encourage customers to use energy more efficiently."  The NOI is in response to language included in the American Recovery and Reinvestment Act that required states to try to implement a policy that would align utility incentives with helping consumers use energy more efficiently as a condition of receiving additional State Energy Program funds. 

That language is generally understood to refer to "decoupling": changes in rate structures to address the fact that under traditional ratemaking policies utilities make more money as consumers use more electricity and gas. This makes it difficult to enlist utilities in efforts to encourage energy efficiency.  Those rate structures also create disincentives for T&D utilities to support behind the meter renewable distributed generation, such as residential roof-mounted solar photovoltaics or home wind turbines, which have the same effect of reducing total energy use by end users, and thus utility profits.  Decoupling is often paired with net metering, which allows home users to use on-site energy generation to offset energy consumed and reduce or in some cases eliminate their retail electricity bill.

The tone of the NOI is, on the whole, skeptical about the prospect of adopting a "decoupling" regime for Maine's transmission and distribution utilities.  The Commission notes Maine's prior experience with decoupling, including a failed implementation with Central Maine Power in the early 1990s, and a series of investigations and reports by the Commission that concluded the negative impacts (or risk thereof) of new rate designs exceeded any potential benefits.  They also note that the state's electricity efficiency programs are already administered by a separate entity, Efficiency Maine, and not the utilities themselves, reducing the conflict of interest inherent in utility-run efficiency programs absent decoupling.

Nonetheless, the Commission seeks input from interested persons on the following questions (additional questions relating to natural gas are omitted here):

1. Is there a need for Maine to implement alternative rate structures or other incentives for T&D utilities that would encourage energy efficiency measures by consumers?
2. Are there rate design or ratemaking techniques that were not considered in the prior investigations into efficiency incentives for Maine’s electricity utilities that could provide substantial benefit to the State?
3. Are there unintended consequences to implementing alternative rate structures or other efficiency incentives for T&D utilities that were not considered previously by the Commission?

Comments in this proceeding, Docket No. 2009-159 are due June 19, 2009, with reply comments to be filed by July 3, 2009.

Safe Passage for Ocean Energy

Yesterday, the Maine Senate voted unanimously in support of LD 1465– An Act to Facilitate Testing and Demonstration of Renewable Ocean Energy Technology (pdf).  As described in an earlier article by Pierce Atwood, this legislation is the result of the work of Maine’s Ocean Energy Task Force (OETF ), which Governor Baldacci established in November 2008 for the purpose of developing a strategy to meet or exceed Maine’s goal to install at least 300 megawatts of offshore wind capacity by 2020. 

The work of the OETF is not yet done, however.  The next challenge is to select the sites appropriate for development.  The OETF has already started this process by reviewing a variety of data and hearing presentations on the siting plans of Massachusetts(pdf) and Rhode Island(pdf).  But the process may prove time-consuming.  A year ago, Massachusetts was the first state to embark on the effort to create a comprehensive planning document that maps out the potential locations for offshore wind and other projects.  A draft of the Massachusetts plan is expected to be release on July 1, 2009; it isn’t expected to be final until January 1, 2010. 

For more information regarding LD 1465 or the Ocean Energy Task Force, contact Sarah Verville (207-791-1371 or sverville@pierceatwood.com) or Elizabeth Butler (207-791-1226 or ebutler@pierceatwood.com).

Renewable Energy Project Finance Seminar - Boston

Pierce Atwood is co-sponsoring a half-day seminar in Boston on June 11, focusing on Renewable Energy Project Finance, with special attention to the new opportunities offered by the renewable energy provisions in the American Recovery and Reinvestment Act, including DOE loan guarantees and changes to tax incentives. William Hewitt and John Gulliver of Pierce Atwood, as well as other renewables experts from the private and public sectors throughout New England, will provide their insights on opportunities and strategies for getting renewable energy projects financed. We hope you will be able to join us for this informative session. 

Location
University of Massachusetts Club
225 Franklin Street
Boston, MA 02110

Date
Thursday, June 11, 2009

Time
7:30 AM - Registration & Continental Breakfast
8:00 AM - 12:00 PM - Program

For full program details and to register, please click here.

Eliciting a Response

Current ISO-NE demand response (DR) programs are set to expire in one year (June 1, 2010) and ISO-NE has initiated a stakeholder process (pdf) to decide what comes next.  Key features of two of the DR programs currently offered by ISO-NE include: 

• Real-Time Price Response Program, under which participants may interrupt their power use when the forecast price of power reaches $100/MWh or more and the ISO lets participants know the eligibility period is open.  Participants are paid $100/MWh or the LMP at the time of their interruption, whichever is higher. 
• Day-Ahead Load Response Program, which allows participants to submit offers to interrupt power use along with submissions of supply offers in the day-ahead energy market.  Participants are paid the Day-Ahead LMP for the cleared interruptions, and real-time deviations are charged or credited at the Real-Time LMP.

In a recent FERC filing (pdf), ISO-NE noted that this stakeholder process touches on a variety of policy issues.  Many of these policy issues reflect the need to encourage demand response (making it economically advantageous to reduce power use at times of peak load and providing DR opportunities to all customer classes, for example) without distorting the market (by offering DR subsidies disproportionate to their actual benefits to transmission system reliability). 

Market-based capacity programs like those currently available at ISO-NE can inspire huge growth in DR, particularly in the wholesale and industrial customer classes.  According to ISO-NE, DR resources (mostly wholesale and industrial) in the region have gone from 100 MW to 2,500 MW since the inception of these programs.  Still, the FERC estimates (pdf at 33) there could be 41 GW of demand response available in the United States; if that estimate’s right, there should be a lot more to be found in New England, especially among customers who lack direct access to capacity programs, like residential customers.  The rapidly emerging SmartGrid standards will have a large impact on how DR programs are designed – and how much access various customer classes have to them.  Makes sense, then, that the most recent meeting of the ISO-NE Demand Resources Working Group was held jointly with the Demand Resources IT Infrastructure Working Group. 

ISO-NE intends (pdf) to file an updated report on this stakeholder process with the FERC by the end of July, 2009, detailing areas of consensus.  Any rule changes resulting from this discussion will be presented to stakeholders and filed with the FERC by the end of 2009.