Eighth Circuit Panel Rules Minnesota Climate Change Law Unconstitutional

Today, the Eighth Circuit determined that the Next Generation Energy Act (“NGEA”), a Minnesota law that established power sector standards for carbon dioxide emissions, was unconstitutional (decision available here). In so doing, the Court affirmed the decision of District Court Judge Susan Nelson, whose 2014 decision we covered in “Court Declares Minnesota Coal Law Unconstitutional: Electrons Favor the Laws of Physics to Those of Governments.”

However, the Eighth Circuit panel arrived at Judge Nelson’s conclusion by a different route. Only one member of the panel – U.S. Circuit Judge James Loken – explicitly agreed with Nelson that the NGEA violated the dormant Commerce Clause. Judge Loken found that the NGEA’s “broad prohibitions plainly encompass non-Minnesota entities and transactions” and “regulate activity and transaction taking place wholly outside of Minnesota” because “when a non-Minnesota generating utility injects electricity into the MISO grid to meet its commitments to non-Minnesota customers, it cannot ensure that those electrons will not flow into and be consumed in Minnesota.  Likewise, non-Minnesota utilities that enter into power purchase agreements to serve non-Minnesota members cannot guarantee that the electricity eventually bid into the MISO markets pursuant to those agreements will not be imported into and consumed in Minnesota.”

By contrast, Judge Murphy disagreed with Judge Loken’s extraterritoriality analysis while Judge Colloton never even reached the dormant Commerce Clause question. Judge Murphy reasoned that because the NGEA’s importation prohibition “bans contracts for power from new large power plants, it thus bans wholesale sales of electric energy in interstate commerce” in direct contravention of the Federal Power Act’s grant of exclusive jurisdiction over “the transmission of electric energy in interstate commerce” to the Federal Energy Regulatory Commission.  Meanwhile, Judge Colloton reasoned that, “[b]y demanding offsets or allowance purchases from a North Dakota energy facility as a condition for contracting to provide power to Minnesota customers, Minnesota’s statute conflicts with the regulatory scheme that Congress designed in the Clean Air Act,” which allows each state to regulate emissions from sources within its borders through State Implementation Plans.

Since the panel was divided on the application of the dormant Commerce Clause to the NGEA, the permissible scope of state regulation of the energy sector remains uncertain. The concurrences in today’s decision in the Eighth Circuit add additional complexity and uncertainty by asserting that Minnesota’s law may be in conflict with the Clean Air Act or preempted by the Federal Power Act. In addition, and with respect to the question of whether state energy policy may run afoul of the extraterritorial doctrine of the dormant commerce clause, the Tenth Circuit recently came to a different conclusion in the face of a similar challenge to Colorado’s renewable portfolio standard (the Tenth Circuit decision can be found here). While the ultimate outcome is uncertain, the Eighth Circuit decision is sure to spark continued discussion and debate. Watch this space for updates as these issues move forward.




MN Court of Appeals Upholds PUC’s Community Solar Order

The Minnesota Court of Appeals filed its decision today affirming the Public Utilities Commission’s August 6, 2015 Order in the community solar garden proceeding, which adopted the partial settlement agreement between certain solar developers and Xcel Energy and decided several crucial aspects of Xcel’s community solar program, including the 5 MW cap on co-located gardens.  Sunrise Energy Ventures, LLC, a major developer in the community solar program, argued on appeal that the Commission engaged in improper and unlawful rulemaking, violated due process, and acted contrary to the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Court of Appeals rejected each of Sunrise’s arguments. The Court found that the Commission had not engaged in rulemaking in its Order, but rather had made reasonable determinations consistent with the statute to modify the program in light of the “overwhelming response” of developers. The Court also found that the reservation letter between the developer and Xcel is not an enforceable contract and cannot serve as the basis for a substantive due process claim, and that the Commission did not violate Minnesota’s open-meeting law by taking a break to “talk to staff” and then immediately voting to adopt the co-location cap. Finally, the Court concluded that the Commission did not violate PURPA by allowing Xcel to refuse interconnection for a community solar garden that would require upgrades over $1 million, because Xcel’s Section 10 tariff already offers developers the ability to interconnect pursuant to PURPA.

Sunrise has 30 days to seek review of the decision from the Minnesota Supreme Court.

U.S. Fish and Wildlife Service Issues Proposed Changes to Eagle Permit Regulations, Opens 60-Day Comment Period

Today the U.S. Fish and Wildlife Service (Service) published notice in the Federal Register of proposed changes to its eagle permitting regulations (Proposed Rule).  Concurrent with the Proposed Rule, the Service issued a Draft Programmatic Environmental Impact Statement (DPEIS) analyzing the proposed changes under the National Environmental Policy Act (NEPA), and a Status Report that estimates size, productivity, and survival rates for bald and golden eagles, and provides recommendations on authorized take limits.  The Service is accepting comments on the Proposed Rule and the DPEIS until July 5, 2016.

Although we are still in the process of evaluating the entire package, the proposed changes represent a significant step forward for applicants seeking regulatory certainty through the eagle permitting process. Here’s a quick snapshot of the proposal:

(Re)extends maximum permit term to 30 years.  As we discussed in a previous post, in August 2015, the U.S. District Court for the Northern District of California set aside the 30-year tenure provision of the 2013 revisions to the eagle permit regulations on NEPA grounds, concluding that the Service had failed to demonstrate an adequate basis in the record for deciding not to prepare an Environmental Impact Statement or Environmental Assessment.  The Proposed Rule, now backed by NEPA analysis that evaluates the 30-year maximum term, once again extends the maximum term for eagle take permits from five to 30 years, subject to recurring five-year check-ins.  In the Federal Register notice, the Service acknowledges that the “5-year maximum permit term is unnecessarily burdensome for businesses engaged in long-term actions that have the potential to incidentally take bald or golden eagles over the lifetime of the activity.” Continue Reading

Stoel Rives Partner Jon Wellinghoff to Join SolarCity as Chief Policy Officer

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.

Developer Requests Clarification of Minnesota PUC’s Community Solar Garden Order

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 pass historic renewable energy bill, with 50% RPS and coal-fired electricity phaseout

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.

Continue Reading

All Sides Agree on Maine’s Replacement of Net Energy Metering

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.

A summary of the legislation is available here (pdf), and the draft bill is available here (pdf).

Center for Biological Diversity Files 60-Day Notice of Intent to Sue the U.S. Fish and Wildlife Service on Final 4(d) Rule for Northern Long-Eared Bat

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.

U.S. Supreme Court Stays Clean Power Plan Implementation: Next Steps

Ed. – originally authored by Kevin Johnson and Thomas Wood.

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

California CPUC Votes to Retain Net Metering, With Modifications

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.”