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.”

U.S. Supreme Court Upholds FERC Demand Response Rule in Energy Story of the Year

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.

U.S. Fish and Wildlife Service Issues Final 4(d) Rule for Northern Long-Eared Bat Under Endangered Species Act

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

U.S Fish and Wildlife Service Opts Not to Appeal 30-Year Eagle Rule Decision, Focuses on Development of Eagle Permitting Program

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

Minnesota Governor Appoints New PUC Commissioner

Yesterday, Minnesota Governor Mark Dayton announced the appointment of Matthew Schuerger to the Minnesota Public Utilities Commission (MPUC).  Mr. Schuerger will replace Commissioner Betsy Wergin, whose term expired January 4, 2016.  Governor Dayton’s Press Release can be found here.

The MPUC consists of five commissioners appointed by the governor to six-year, staggered terms. Under Minnesota law, no more than three commissioners can be of the same political party and at least one commissioner must reside at the time of appointment outside the Twin Cities metropolitan area.  Once Commissioner Wergin steps down, Commissioner Tuma will be the remaining outstate Commissioner.

Once Mr. Schuerger starts in his new role, all MPUC Commissioners will have been appointed by Governor Dayton.

MISO Proposes Interconnection Queue Reform To Address Continuing Delays

Midcontinent Independent System Operator (MISO) is proposing another round of interconnection queue reform.  On December 31, 2015, MISO filed proposed revisions to its Open Access Transmission, Energy and Operating Reserve Markets Tariff with the Federal Energy Regulatory Commission (FERC). The revisions, which amend MISO’s Generator Interconnection Procedures, would be MISO’s fourth significant set of queue reforms since 2008, but the first since 2012. MISO is seeking to address what it describes in its filings as “significant delays” in the generator interconnection queue, particularly in the Definitive Planning Phase (DPP), that MISO argues are primarily caused by higher-queued projects withdrawing from the queue and forcing unscheduled restudies of the lower-queued projects.  To address these delays and to prepare for anticipated “significant new renewable and gas development in the footprint in response to the changing regulatory landscape,”  MISO says that it is seeking with this proposal to “optimize the restudy process” while also addressing other concerns identified by MISO and in the stakeholder process.  MISO has requested that its proposed tariff revisions be effective as of March 30, 2016.

Highlights of the proposal include:

  • A System Impact Study at each of the three DPP Phases;
  • Two “designated off-ramps” or Decision Points, allowing a customer to withdraw from the queue on a “more structured basis,” and which occur immediately after the System Impact Studies in DPP Phases I & II;
  • Addition of two new milestone payments, M3 and M4, in DPP Phases II and III, incentivizing withdrawal at the Decision Points and funding cost increases caused by withdrawing projects (the immediately preceding milestone payment would be refundable to a withdrawing project);
  • Removal of the required restudy due to a change to a higher-queued project for any Interconnection Customers with a completed Generator Interconnection Agreement, unless ordered by FERC;
  • A voluntary “Pre-Queue Feasibility Phase” to replace the current Interconnection Feasibility Study and System Planning and Analysis Phase

MISO’s cover letter summarizing the 1,600-page filing is available here. (pdf)

Utah PSC Compromises, Reduces Maximum PPA Contract Terms under PURPA to 15 Years

The Utah Public Service Commission (PSC) issued its decision today on PacifiCorp’s request to shorten the maximum term of power purchase agreements (PPAs) with qualifying facilities (QFs) from 20 years to three years.  The PSC agreed to reduce the maximum term from 20 to 15 years, concluding:  “We believe a 15-year term strikes the appropriate balance at this time by mitigating a fair portion of the fixed-price risk ratepayers would otherwise bear while allowing QF developers and their financiers a reasonable opportunity to adjust to this more modest change in business practice.”

My colleague Greg Monson provided the following analysis:

PacifiCorp’s request is similar to requests made in its other states and by sister-company NV Energy in Nevada.  PacifiCorp provided evidence of the substantial volume of QF contracts and pending requests compared to system needs, the price differential between the current avoided costs and market, and the inconsistency of 20-year, fixed-price contracts with current resource planning and hedging policies.  The Utah Division of Public Utilities (DPU), the state agency charged with representing the public interest, supported the request to shorten the maximum term, but to five years rather than three.  The Utah Office of Consumer Services (OCS), the state agency charged with representing the interests of residential and small commercial customers, expressed concern about the fixed-price risk to ratepayers, but opposed the request, arguing that “this extreme change [in contract duration] may discourage all new QF development … contrary to Federal and State laws [that] were enacted specifically to encourage the development of small power producers or QFs.”  The Renewable Energy Coalition (REC), the Rocky Mountain Coalition for Renewable Energy (RMCRE), Sierra Club and Utah Clean Energy (UCE) also filed testimony opposing the request, arguing that granting it would end QF project development in Utah and was contrary to PURPA and the Utah law.

Key findings and conclusions of the PSC are:

  • “We reject the notion federal regulations require QF developers to enjoy ‘investor certainty’”
  • “no federal or state statute or regulation requires a 20-year contract term”
  • “it falls to [the PSC] to exercise its discretion to establish a contract term that advances the policy interests underlying PURPA and [the Utah law] without unduly burdening ratepayers with excessive price risk”
  • “even if it were incumbent on the Commission to establish contract terms that ensured the ability of QF developers to obtain financing, the record does not demonstrate QF developers will be unable to obtain financing on projects with shortened contract terms”
  • “Although we find the record supports taking action to protect ratepayers against undue fixed-price risk, we believe a more measured response is appropriate than either the 85 percent reduction for which PacifiCorp advocates or the 75 percent reduction sought by the [DPU]”

Download a copy of the decision (PDF)

Xcel Energy’s Community Solar Garden Tariff Final this Friday

*Update: Xcel has now filed its revised tariff (pdf)

The Minnesota Public Utilities Commission published its Order (pdf) Tuesday approving Xcel Energy’s revised tariff for its Community Solar Garden Program contingent on certain changes being made. After Xcel Energy filed its tariff following programmatic changes made by the Commission earlier in the year, several parties objected to Xcel Energy’s interpretation. The Commission heard these arguments on November 19. As a result of decisions made during those deliberations, the Order:

  • Modifies Xcel’s definition of co-located community solar gardens (casting aside efforts to agree on a geographic safe-harbor),
  • Refines the material-upgrade limitation on interconnection,
  • Clarifies the standard to be applied by the Independent Engineer when resolving interconnection disputes,
  • Affirms the ability of cap-compliant projects to transfer their interconnection-queue positions, and
  • Requires Xcel to develop an exception process to allow projects to interconnect when possible before installation of telecommunications upgrades, which can have 12-15 month build-out timelines attached to them.

The Order requires that Xcel file its tariff reflecting the Commission’s changes by Friday, December 18.

CPUC Proposes to Preserve Retail Rates for Residential Distributed Generation

The California Public Utilities Commission released a proposed decision yesterday in its proceeding concerning the future of net energy metering (NEM) for customers of the state’s three largest utilities who install renewable distributed generation (DG) on their properties. In comments filed in early-August, Pacific Gas and Electric (PG&E), Southern California Edison (SGE), and San Diego Gas and Electric (SDG&E) had argued 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.”

The proposed decision also includes an expansion of the NEM successor tariff to include customer-generators with systems larger than 1 MW, so long as the customer pays all Rule 21 interconnection costs. The proposed decision does contain 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 $5 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 proposed decision will also require all NEM customers interconnecting on or after January 1, 2018 to take service on a time-of-use (TOU) rate with no option to opt out, and will eventually require all customers using the NEM successor tariff, like all residential customers generally, to take service on a TOU rate by 2019. The Commission will revisit the NEM successor tariff for review in 2019, due to the coinciding institution of default TOU rates at that time.

The Commission determined that the virtual net metering (VNM) and net metering aggregation (NEMA) tariffs “should be maintained and updated consistent with the provisions of the NEM successor tariff established by this decision.” The Commission noted specifically that NEMA is important for allowing agricultural customers to take advantage of renewable DG. The Commission also found that, while the AB 693 Multifamily Affordable Housing Solar Roofs program addresses barriers to the growth of DG in disadvantaged communities, a program should be developed that further expands VNM to cover members of disadvantaged communities who do not live in multifamily housing.

The three utilities generally responded negatively, reiterating arguments that the proposed decision continues to force non-customer-generators to help pay for costs that customer-generators impose on the grid. Solar advocates, meanwhile, applauded the proposed decision, particularly the component that preserves retail rates paid to customer-generators. The Commission will make a final decision as early as January 28, 2016.

Solar Electric Power Assoc. Releases Community Solar Report

The Solar Electric Power Association (SEPA) recently released a Community Solar Program Design Models report as part of a grant from the U.S. Department of Energy’s Solar Market Pathways program. The report is a resource for anyone interested in community solar, but is particularly useful to those involved in developing a community solar program in their community. The report details the current community solar design models, breaking down the program design into 12 key decisions and discussing which options are the most prevalent, as well as the ramifications of these decisions. For example, the report lays out the Four Steps to Community Solar Program Success: 1) “Identify clear program goals and conduct due diligence on your local market to ascertain whether these goals are feasible,” 2) “Select design options for the community solar program,” 3) “Identify marketing plan,” and 4) “Monitor program satisfaction.” The report finds that 60% of community solar programs are “utility-led,” like the program Xcel Energy is developing based on a mandate from the Minnesota Legislature, and 40% of programs are “third-party programs.” The report also contains the results of SEPA’s survey of all 68 active community solar program administrators to gather information about subscription rates, generating capacity, expansion, development time, and cost. SEPA’s next steps are to conduct customer research to determine potential subscriber preferences, and to assist utilities with design and implementation of new CSPs. The full report is available here (pdf).

 

 

 

 

LexBlog