I just wanted to pass along word to readers that Stoel Rives partner and Renewable + Law blog author Jon Wellinghoff will be leaving us to join SolarCity as their new Chief Policy Officer. Read SolarCity’s official announcement. We’ve enjoyed working with Jon as a member of the Stoel Rives Energy Team. We’d like to wish him the best of luck in his new endeavor and look forward to continuing to work with him when he joins our client, SolarCity. He’s joining the company at a significant moment in the solar industry’s development. As Elon Musk just tweeted yesterday, SolarCity customers recently produced enough energy in one day to charge every Tesla in the world.
Minnesota solar developer SolarStone Partners, LLC filed a Motion for Clarification of the Minnesota Public Utilities Commission’s September 2014 Order Approving Solar-Garden Plan with Modifications. Specifically, SolarStone is requesting clarification of the Commission’s interpretation of the requirement in the Community Solar Garden Statute that a project must be located within the utility’s service territory. One of SolarStone’s community solar garden projects planned in Chisago County is primarily located within Xcel Energy’s service territory, but a small portion of the project protrudes outside of Xcel’s territory. Because the project is not entirely within its territory, Xcel declined to advance the project through the interconnection process. SolarStone argues that its project is compliant with the program because its points of interconnection/common coupling are within Xcel’s territory. We will update this story as it develops. A copy of SolarStone’s Motion is available here (pdf).
Oregon legislators passed Senate Bill (SB) 1547 into law yesterday, creating aggressive timetables for eliminating coal-fired electricity from the State and setting a 50% Renewable Portfolio Standard (RPS) by 2040. A diverse group of utilities, consumer advocacy organizations, and renewable energy advocates support the bill. Next stop for SB 1547 is Oregon Governor Katherine Brown’s desk, where she is expected to sign the bill into law.
Key provisions and significance of SB 1547 include:
50% RPS by 2040
Oregon’s two largest utilities – PacifiCorp and PGE – will have a 50% RPS standard by 2040, meaning 50% of their electricity supply must be derived from renewable energy sources. The two largest utilities serve approximately 70% of Oregon customers’ electricity needs. There was no change to the existing requirements on consumer-owned utilities.
- This is one of the most aggressive RPS standards in the nation, matched only by California and New York, which have a 50% target by 2030, Vermont, which has a 75% target by 2032, and Hawaii, which has a 100% target by 2045.
- The existing ratepayer protections relating to RPS compliance were retained, capping the incremental costs of compliance at 4% of the utilities annual revenue requirement for a compliance year. A new provision was added to permit the Oregon PUC to temporarily suspend RPS compliance if the utility determines that grid reliability is seriously compromised.
- The Oregon PUC will implement competitive bidding rules governing electric companies’ RPS implementation plans to ensure that electric companies acquire electricity from diverse renewable energy generators.
Maine appears poised to replace its net-energy metering (NEM) program with new legislation that is projected to increase the state’s solar photovoltaics (PV) penetration by over 12 times the current installed capacity by 2022. The legislation has the support of a broad coalition of consumer advocates, utilities, solar installers and environmental advocates, by contrast to the contentious and divisive NEM battles in states like California, Nevada and Arizona. (One prominent solar advocate, The Alliance for Solar Choice, has stated that the current NEM program should be kept in place until the new policy demonstrates that it will support solar growth.)
The move comes as Central Maine Power, the state’s largest utility, is nearing the 1 MW cap on NEM, and as the state has undertaken the ambitious effort to determine the proper value of solar. A study conducted last year found that the value of solar might be as high as $0.33 per kWh, whereas under the current NEM framework, customers with rooftop solar who export energy to the grid are paid the retail rate of $0.13 per kWh.
The new legislation provides that Maine utilities will enter into long term contracts for a total of 248 MW over the next five years, divided between four market segments: residential and small business, community solar gardens, large commercial and industrial, and grid scale projects (up to 5 MW). Nearly all of Maine’s 20 MW of solar PV is currently sited at residential and small business customers, and under the new legislation, that capacity could increase to 118 MW, or 47% of the market. Community solar could increase to 45 MW, or 19% of the market, large commercial and industrial could increase to 25 MW, or 10% of the market, and grid scale could increase to 60 MW, or 24% of the market.
Contract terms will vary based on the market segment. For example, residential and small business customers can either sell the entire output of their system to the utility or use the generation to offset their consumption and sell any excess generation. Unlike NEM, where the price per kWh varies over time, the price per kWh under the new legislation is set by the Maine Public Utilities Commission (PUC) in order to meet installation targets, subject to an overall cap on the cost of the program. The price is expected to step down as installation grows.
Existing NEM customers can continue under that program for 12 years, but NEM is not available to new customers once the program goes into effect. The Maine PUC will review the program after 18 months or 21 MW of installed capacity, whichever comes first.
As we discussed in a previous post, on January 14, 2016, the U.S. Fish and Wildlife Service (Service) published a final 4(d) rule under the Endangered Species Act for the northern long-eared bat. As we noted, although the final 4(d) rule was widely viewed as a “win” for the wind industry, environmental organizations were generally displeased, arguing that the species should have been listed as endangered instead of threatened. Now, a coalition of environmental organizations led by the Center for Biological Diversity is threatening to sue the Service, alleging that the final 4(d) rule is unlawful. In addition to complaining that the species should have been listed as endangered rather than threatened, the notice alleges that the final 4(d) rule fails to adequately provide for the conservation of the species. The environmental groups contend that the measures adopted by the Service to protect hibernacula and roost trees are not sufficiently protective.
We anticipate that the environmental groups will file suit in federal district court following expiration of the 60-day notice period. We are monitoring this case closely and will provide updates on this blog if and when litigation ensues.
The U.S. Supreme Court’s order on February 9, 2016 staying EPA’s implementation of the Clean Power Plan (CPP) will create at least a year of uncertainty about the shape of the future electric power regulatory framework, with implications for states, utilities and other electric power providers, and for the many other stakeholders potentially affected by the CPP. The CPP is the regulatory program issued by EPA on October 23, 2015, that requires states to develop plans to reduce carbon (CO2) emissions by meeting either state-specific mass caps (tons/year) or state-specific emission rate intensity limits (lb/netMWh). The CPP seeks to establish a whole new style of regulation using authority under section 111(d) of the Clean Air Act.
Supreme Court Halts CPP Implementation
Twenty-nine (29) states and a number of utilities, labor unions and trade associations challenged the legality of the CPP. These appellants sought a stay of the rule from the D.C. Circuit in November 2015. The petition for a stay was denied on January 21, 2016. The appellants then appealed to the U.S. Supreme Court — a move that most pundits thought was futile as it is extremely rare for the Supreme Court to grant such a stay. In order to grant a stay, the Court needed to find that if the D.C. Circuit were to uphold the CPP, (1) there is a reasonable probability that four Supreme Court Justices would vote for review of the D.C. Circuit opinion; (2) there is a fair prospect that a majority of the Supreme Court would vote to reverse the D.C. Circuit’s opinion upholding the CPP; and (3) that there is a likelihood that immediate, irreparable harm would result from the denial of a stay. By granting the stay, it appears that five of the nine Supreme Court justices (Roberts, Scalia, Alito, Kennedy and Thomas) indicated that they believe there is a fair prospect that they would vote to overturn the D.C. Circuit were the D.C. Circuit to uphold the CPP. The Court’s action prevents EPA from further implementation of the CPP until the petitioners’ appeal is decided. The underlying challenge to the CPP is proceeding on an expedited schedule with oral argument set for June 2 and 3, 2016.
In addition, another factor in the Court’s stay decision was likely the pending deadlines for states to take compliance actions. The deadline for states to submit initial plans demonstrating how they would comply with the CPP was September 6, 2016. While virtually all states were likely to request an extension for plan submittal until September 2018, states still needed to show progress on their plans by this September, and many states, including several of the 29 appellant states, were beginning the planning process.
Next Steps: Back to the D.C. Circuit Continue Reading
The California Public Utilities Commission yesterday adopted – by a 3-2 vote – a proposed decision revising the net energy metering (NEM) tariff for customers of the state’s three largest utilities who install renewable distributed generation (DG) on their properties. To the dismay of the dissenting commissioners, the final decision adopted late proposed changes that exclude transmission costs from the non-bypassable charges that will be imposed on NEM customers.
Here is a summary of key provisions in the decision:
- Pursuant to the decision, NEM customers will continue to be paid the retail rate of energy for excess generation sent back to the grid. In doing so, the CPUC adopted a different approach then the Nevada PUC, which recently decided to end payments at retail rates for excess generation from net metered systems in favor of payment at wholesale rates.
- The decision declined to impose any demand charges, grid access charges, installed capacity fees, standby fees, or similar fixed charges on NEM residential customers, at least under the latest NEM tariff. This aspect of the decision also differs from the recent decision out of the Nevada PUC, which imposed fixed charges on NEM customers.
- The decision contains a new requirement that customer-generators “pay a reasonable interconnection fee” to the applicable utility estimated to be about $75-$100, and also imposes non-bypassable charges for each kilowatt-hour of electricity that the customer-generator consumes from the grid, regardless of how much they export to the grid, which will likely add approximately $4 to the customer-generator’s bill each month. The Commission found that “[c]ontinuing net energy metering with NEM customers paying charges for interconnection and paying nonbypassable charges for all electricity consumed from the grid is likely to allow customer-sited renewable DG to continue to grow sustainably.”
- The decision also includes an expansion of the NEM tariff to include customer-generators with systems larger than 1 MW, so long as the customer pays all Rule 21 interconnection costs.
- The decision will also require all NEM customers in SCE and PG&E service territories to take service on a time-of-use (TOU) rate as soon as such rates are available, while SDG&E customers can remain on tiered rates for the first five years after the new TOU rates are approved in 2017.
- The Commission will revisit the NEM tariff for review in 2019, due to the coinciding institution of default TOU rates at that time.
- The decision rejects requests by Pacific Gas and Electric (PG&E), Southern California Edison (SGE), and San Diego Gas and Electric (SDG&E) for many changes to the current framework, including one that would have allowed them to charge customer-generators at the retail rate for electricity they consume from the grid and pay a lower rate for energy that customer-generators export to the grid. However, the CPUC rejected that proposal for now by “[d]eclining to impose any demand charges, grid access charges, installed capacity fees, standby fees, or similar fixed charges on NEM residential customers while the Commission is working on how, if at all, any such fees should be developed for residential customers.”
In the biggest consumer energy story of the day, and perhaps the decade, the U.S. Supreme Court today upheld FERC’s jurisdictional authority in FERC Order 745. Read the Decision here (PDF). The so called Demand Response Rule permits consumer energy products and services, such as demand response, to participate in wholesale energy markets, and to receive full compensation for that participation at a level equal to traditional generators. So as Amory Lovins always maintained, a megawatt should be equal to a megawatt. Now that this principle has been firmly established in Federal law for the first time, the impact for consumers will be massive (hundreds of billions of dollars over the next 20 years) – for two reasons.
First, consumers will now have an opportunity to receive more value from the new energy technology they put into their homes and businesses. This is because a smart thermostat not only will lower your bills by more precisely controlling the amount of heating or cooling energy you use; it will also provide you revenue by being able to participate in demand response programs in the wholesale energy markets. This also applies to all other controls for appliances in the home, to solar PV systems on the roof, to batteries and even plug-in electric vehicles. And it applies not only to consumers in their homes, but businesses too. Large commercial and industrial (C&I) customers with the ability to bid demand response into the wholesale market are now assured the ability to do so, which will benefit the C&I customer and the system as a whole.
So the ruling today will be a tremendous boon for consumer side energy technology expanding opportunities for digital controls, solar PV, and battery storage. Making those technologies more valuable and therefore more affordable. And of course it is also a boon for providers of consumer side energy resource or distributed energy resources (DERs) like demand response companies and distributors of solar PV systems and the manufacturers of such products. Just look at EnerNOC’s stock, a demand response and DERs service company. Their stock shot up over 70% just today alone on the announcement of the Supreme Court decision.
The second consumer benefit today’s Court decision makes possible is the promise of significantly increased competition for both fossil fuel and other traditional central station generators from consumer side DER assets like demand response and distributed generation and battery storage. The introduction of these assets into wholesale markets will significantly drive down wholesale energy prices by billions of dollars each year. The wholesale energy market region in the Mid-Atlantic of PJM alone had estimated that demand response saved consumers in their market as much as $12 billion annually. Thus all consumers will benefit from the Supreme Court decision today. Not just those who can afford to install new energy technology. And globally, today’s ruling will also mean the expansion of more clean distributed resources and the reduction of carbon emissions from fossil fuel generation from central station power plants.
In April 2015, the U.S. Fish and Wildlife Service (“Service”) published a final decision to list the northern long-eared bat as threatened and, rather than publishing a final 4(d) rule, opted to publish an interim 4(d) rule and open a 90-day comment period to gather additional information and potentially refine the interim 4(d) rule.
As we discussed in a post last year, the effect of the interim 4(d) rule depended on the location of a particular activity. For areas of the country not affected by white-nose syndrome, the interim 4(d) rule exempted incidental take from all activities. For areas of the country affected by white-nose syndrome, the interim 4(d) rule exempted from Endangered Species Act take prohibitions the following activities: (1) forest management practices, (2) maintenance and limited expansion of transportation and utility rights-of-way, (3) prairie habitat management, and (4 ) limited tree removal projects, provided these activities protected known maternity roosts and hibernacula. Under the interim 4(d) rule, those activities were exempted provided: (1) the activity occurred more than 0.25 mile (0.4 km) from a known, occupied hibernacula, (2) the activity avoided cutting or destroying known, occupied roost trees during the pup season (June 1–July 31), and (3) the activity avoided clearcuts (and similar harvest methods, e.g., seed tree, shelterwood and coppice) within 0.25 mile (0.4 km) of known, occupied roost trees during the pup season (June 1–July 31). Thus, with a few narrow exceptions, the interim 4(d) rule prohibited all incidental take within areas of the country affected by white-nose syndrome, including take resulting from the operation of utility-scale wind turbines. Continue Reading
On January 19, 2016, the U.S. Department of Justice (DOJ) dropped its Ninth Circuit appeal of U.S. District Judge Lucy Koh’s ruling that set aside the U.S. Fish and Wildlife Service’s (“Service”) rule to extend the maximum term for programmatic “take” permits under the Bald and Golden Eagle Protection Act (“Eagle Act”) to 30 years for failure to comply with the National Environmental Policy Act (“NEPA”).
As we discussed in our previous post, in August 2015 the court set aside the 30-year rule on NEPA grounds, concluding that the Service had “failed to show an adequate basis in the record for deciding not to prepare an EIS–much less an EA–prior to increasing the maximum duration for programmatic eagle take permits by sixfold.” The Court found the Service’s reliance on certain U.S. Department of Interior categorical exclusions misplaced. According to the Court, the Service failed to establish that the decision was “administrative” or “procedural” in nature and failed to address concerns by its own experts that the rule revisions might have highly controversial environmental effects. Importantly, however, the court’s decision to set aside the 30-year rule only applied to the 30-year permit tenure provision of the 2013 rule amendments. Other components of the 2013 rule amendments were left intact, including the 5 year permit renewal and assignment provisions. Continue Reading