Oregon PUC Issues Guidance on Energy Storage Program

Actions are underway  at the Oregon Public Utility Commission (the “PUC”) to implement HB 2193, Oregon’s energy storage legislation.  HB 2193 requires that PacifiCorp and Portland General Electric (“PGE”) submit proposals for energy storage systems capable of storing at least 5 MWh of energy – with an aggregate capacity not to exceed one percent of each company’s peak load in 2014 – by January 1, 2018.

On December 28, 2016, the PUC issued Order No. 16-504 (the “Order”), setting forth guidelines and requirements for PacifiCorp and PGE to follow in submitting these proposals.  Approved by Chief Administrative Law Judge Michael Grant on January 5, 2017, the Order adopts project guidelines, proposal guidelines, storage evaluation requirements, and competitive bidding requirements for PacifiCorp and PGE storage project proposals.

  • Project Guidelines

The PUC’s project guidelines encourage PacifiCorp and PGE to submit proposals for “multiple, differentiated projects that test varying technologies or applications[.]”  To that end, the guidelines request that PacifiCorp and PGE submit a portfolio of projects that include varying technology types and levels of maturity.  The companies are also encouraged to consider strategically located projects, and to identify “qualified vendors and viable energy storage technologies through a Request for Information (RFI) process.”

  • Proposal Guidelines

Adopted proposal guidelines request that PacifiCorp and PGE include in their project submissions information regarding each project’s technical specifications, cost, benefits to the electric system (as well as a methodology for determining such benefits), and cost-effectiveness, among other project-specific information.

  • Storage Evaluation Requirements

HB 2193 requires the PUC to develop a multi-step process for evaluating projects’ system-wide storage potential.  Under the Order, PUC staff will “convene workshops to develop a framework for the electric companies’ evaluations,” with the framework to be presented at a special public meeting by March 31, 2017.  PacifiCorp and PGE must then prepare and file evaluations with the PUC by June 1, 2017; another special public meeting will be held by July 21, 2017 for stakeholder and PUC input regarding the evaluations.  Final versions of PacifiCorp’s and PGE’s evaluations must be filed with the PUC by January 1, 2018.

  • Competitive Bidding Requirements

HB 2193 projects are subject to competitive bidding requirements, unless a project may only be developed by a single vendor or contractor.  PacifiCorp and PGE are responsible for demonstrating that they used a fair, competitive process to award HB 2193 projects, and must provide an opportunity for the PUC and stakeholders to comment on any request for proposals.

Projects authorized under HB 2193 must be procured by PacifiCorp and PGE by January 1, 2020.

Katie Sieben Appointed to Minnesota Public Utilities Commission, and Nancy Lange Appointed as Chair

Yesterday, Governor Mark Dayton announced his appointment of Minnesota State Senator Katie Sieben to a six-year term on the Minnesota Public Utilities Commission (MPUC). He also appointed current MPUC commissioner Nancy Lange as chair of the MPUC, filling the vacancy left by outgoing chair Beverly Jones Heydinger. Both Sieben and Lange will begin their terms on January 23, 2017.

The Governor’s press release can be found here.

U.S. Fish and Wildlife Service Issues Final Revised Eagle Rule

Today the U.S. Fish and Wildlife Service (Service) published notice in the Federal Register of a long-anticipated final rule revising its eagle permitting regulations (Revised Eagle Rule). Concurrent with the Revised Eagle Rule, the Service issued a Final Programmatic Environmental Impact Statement (PEIS) analyzing the Eagle Rule revision under the National Environmental Policy Act (NEPA). Although we are still in the process of evaluating the entire package and have concerns with certain aspects of the Revised Eagle Rule, many of the proposed changes represent a step forward for applicants seeking regulatory certainty through the eagle permitting process. Here’s a quick snapshot of the changes:

(Re)extends maximum permit term to 30 years. As we discussed in a previous blog 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 Revised Eagle 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 “[t]he 5-year maximum duration for programmatic permits appears to have been a primary factor discouraging many project proponents from seeking eagle take permits. Many activities that incidentally take eagles due to ongoing operations have lifetimes that far exceed 5 years. We need to issue permits that align better, both in duration and the scale of conservation measures, with the longer-term duration of industrial activities, such as electricity distribution and energy production. Extending the maximum permit duration is consistent with other Federal permitting for development and infrastructure projects.”

Applies practicability standard to all permits. Under the previous rule, applicants for standard (non-programmatic) permits were required to reduce potential take to a level where it was “practicably” unavoidable, but applicants for programmatic permits were required to meet a higher standard (reducing take through the implementation of advanced conservation practices (ACP) to a level where remaining take is “unavoidable”). The Revised Eagle Rule applies the “practicability” standard to all eagle take permits and removes the “unavoidable” standard from the permit program. Thus, all permits will contain the standard that take must be avoided and minimized to the maximum degree practicable. Continue Reading

Appeals Court Sides with Wind Farm on PPA Risk Allocation

This week the Seventh Circuit Court of Appeals issued a decision that could help clarify the allocation of risk in power purchase agreements (PPAs).  In Benton County Wind Farm LLC v. Duke Energy Indiana, Inc., the court settled a PPA dispute by concluding that the contract required the utility (Duke) to pay the wind farm (Benton) for energy even when Midcontinent Independent System Operation (MISO) market prices are negative (due to oversupply of electricity generation in the area) and Duke has to pay both MISO and Benton for accepting the wind farm’s output.  The key provision in the PPA required Duke to pay Benton liquidated damages if Duke failed to accept all of Benton’s electrical output (except in certain circumstances). Since MISO changed its rules in 2013 to remove wind farms constructed after 2005 from “must-run” status, Benton has been curtailed by MISO when wind overtaxes the grid, which in the case of Benton occurs about 41% of the time the wind farm could otherwise be operating. The court reasoned that because, under the PPA, Duke must pay liquidated damages caused by its failure to obtain transmission service, “[t]he risk of inadequate transmission was contemplated by the contracting parties and allocated to Duke.” The court also noted how these provisions implicate project financing for renewable energy as well as transmission development:

Potential buyers and sellers of electricity could and did foresee when negotiating this contract (and others like it) that electrical grids may be swamped by new sources of renewable power, which usually is located far from the centers of demand. They needed to allocate the risk of that development, which predictably would compel MISO to alter its rules for which sources could put power on the grid. Allocating the risk to Benton would have made it hard, perhaps impossible, to finance the project’s construction, while leaving Duke and similar utilities no incentive to expand the regional grids as wind power became available. Allocating the risk to Duke facilitates both construction of renewable-energy sources and better incentives to match the size of the transmission grid to the capacity for local generation.

While the decision, which was a reversal from the district court’s decision, applies narrowly to this contract, the reasoning could have wider ramifications for future PPA negotiations and interpretation. You can read the full decision here (PDF).

NARUC Releases Final DER Compensation Manual

Today, the National Association of Regulatory Utility Commissioners (NARUC) released its final manual on distributed energy resources (DER) compensation.  The draft manual was circulated for review and comment in August 2016, and is intended to help jurisdictions navigate the policy and stakeholder considerations behind DER compensation.

Read our previous post for more information on NARUC’s DER compensation manual.

 

Xcel Wins Approval to Transform Minnesota Generation Fleet

Today, the Minnesota Public Utilities Commission approved Xcel Energy’s dramatic proposal to shift away from coal generation toward renewable energy.   In authorizing the company’s 2016-2030 Integrated Resource Plan (RP-15-21), the Commission directed Xcel to retire two large coal units capable of generating approximately 680 MW each, procure at least 1,ooo MW of wind by 2019, procure at least 650 MW solar by 2020 , begin the process of procuring replacement generation for the coal units in mid-2020s, and acquire at least 400 MW of demand response resources by 2023.

Xcel has already started the wind procurement process with an RFP for up to 1,500 MW issued last month.  The required solar resources are likely to be procured through Xcel’s community solar garden program, but Xcel also is authorized to pursue other cost effective solar resources.   With respect to other replacement generation for the Sherco 1 and 2 coal units now slated to be shutdown, the Commission authorized Xcel to file a petition for a certificate of need to select replacement resources.  Xcel had proposed to build a 750 MW combined cycle gas facility to be located at the Sherco site in Becker, Minnesota, but the Commission determined that a final decision on that proposal and other alternatives (such as additional renewable energy and demand side options) should be made in a subsequent certificate of need proceeding.  Longer term, the Commission also directed Xcel to study options and scenarios for orderly and cost effective retirement of its other baseload resources, including two other large coal units and the company’s nuclear fleet.

Southern California Edison to bring 125 MW of clean energy resources to Orange County

Around the country clean energy resources, energy efficiency and demand response are quickly being adopted alongside more traditional resources. Southern California Edison (“SCE”) recently contracted for an assortment of clean energy resources that will be used in a groundbreaking attempt to see whether those resources can supply electricity to a densely populated area – Orange County – with the same reliability as a traditional power plant.[1]

  • Project Name: The Preferred Resources Pilot.
  • Goal: The multiyear study is designed to determine whether these preferred resources –including solar, wind, battery storage, energy efficiency and demand response – can be used to safely, reliably and affordably serve the electrical needs of customers in a real-world environment,[2] and to determine if more gas-powered capacity is needed in the region.[3]
  • Preferred Sources: Preferred sources include solar and wind power, along with demand response and energy efficiency products.

 

  • Potential Consequences: Proving the capabilities of preferred resources may defer or eliminate the need for new gas-fired generation in the PRP region.[4]
  • Territory: A large part of the cities of Irvine, Tustin, Santa Ana and Newport Beach, as well as all or parts of the cities of Aliso Viejo, Corona del Mar, Costa Mesa, Laguna Beach, Laguna Woods, Laguna Hills, Laguna Niguel, Lake Forest and Mission Viejo. The area is home to approximately 204,000 SCE residential customers and 30,000 SCE commercial and industrial customers.[5]
  • Current Accomplishment: SCE recently contracted with six developers for 125 MW of power representing an assortment of battery storage, “demand response”[6] and the combination of solar and battery storage resources. These clean energy resources are expected to come online between 2019 and 2020 and will add to the 136 MW of “preferred” clean energy resources that have already been acquired for the Preferred Resources Pilot.[7] The utility’s combined 261 MW of clean energy in the pilot is enough to power about 195,000 customers, moving SCE closer to a 100% adoption in Orange County.[8]
Developer Product Capacity (MW) Term

(Years)

Commercial Online Date
AMS Demand Response from Energy Conservation and Battery Storage 40 15 Jan. 2019 –

Jan. 2020

Convergent Battery Storage 35 20 Dec. 2019
Hecate Battery Storage 15 10 Jan. 2020
NextEra Battery Storage 10 15 Jan. 2020
Demand Response from Energy Conservation and Battery Storage 10 15 June 2018 – June 2019
NRG Hybrid of Solar and Battery Storage 10 15 April 2019 – August 2019
Swell Demand Response from Battery Storage 5 15 June 2019
TOTAL:   125

For more details about Preferred Resources Pilot, please consult SCE’s webpage at http://www.edison.com/home/innovation/preferred-resources-pilot.html.

 

[1] http://insideedison.com/stories/orange-county-pilot-tests-whether-clean-energy-resources-can-meet-major-metro-needs.

[2] Id.

[3] http://www.utilitydive.com/news/socal-edison-seeks-125-mw-of-clean-energy-resources-for-orange-county/426620/

[4] http://www.edison.com/home/innovation/preferred-resources-pilot.html.

[5] Id.

[6] Demand response means customers reduce their use of electricity from the power grid in response to an electronic signal. SCE has continued to add demand response and storage projects in its power portfolio in the wake of the Aliso Canyon methane gas leak disaster and regulatory mandates. Part of those efforts include a partnership with Nest thermostats to connect 50,000 homes in SCE’s service territory and transform them into a virtual power plant capable of controlling about 50 MW of load reduction. See supra note 3.

[7] See supra note 1.  Please see the chart below for more details.

[8] See supra note 3.

MISO Transmission Owners’ Return on Equity Cut by FERC

Following a decision of the Federal Energy Regulatory Commission (FERC) released last week that cuts transmission owners’ return on equity (ROE) by more than 200 basis points,[1] ratepayers in the Midcontinent Independent System Operator, Inc. (MISO) footprint will save an estimated $200 million per year.

Spurred by industrial customers’ challenge to MISO’s ROE rate in 2013, FERC ultimately found in its September 28, 2016 order that MISO’s ROE of 12.38% – which had been in place since 2002 – was unjust and unreasonable, and reset it to a base rate of 10.32%.[2]  Transmission owners may also qualify for transmission incentive ROE adders, although the maximum ROE rate may not exceed 11.35%.[3]  FERC also ordered that refunds be issued on a prospective basis for the period from November 12, 2013 through February 11, 2015.[4] Continue Reading

New BLM Wind and Solar Development Guidelines on Public Lands Expected Soon

With a goal to spur wind and solar development on public lands, the Bureau of Land Management (BLM) is expected to soon release a new rule that will streamline approval of new renewable energy projects.

First proposed for advance notice and comment in 2011, the rule would amend BLM regulations at 43 C.F.R. §§ 2800 and 2880 and implement, among other things, competitive leasing processes, developer incentives, revised rent and fee schedules and new megawatt (MW) capacity fees for wind and solar energy projects on BLM lands.[1]

The provisions depend on whether the project is located inside or outside “designated leasing areas” (DLAs), as determined by the BLM, which include “preferred areas” for development.[2]

Competitive Leasing

Lands within DLAs will be subject to competitive bidding procedures that provide for variable offsets to developers. Bidding developers may also pre-qualify for the offsets – limited to 20 percent of the high bid – by meeting factors set forth in a Notice of Competitive Offer.  While these factors will vary from lease to lease, they may include whether the developer has a power purchase or interconnection agreement in place for the project.[3]

Outside DLAs, the proposed rule amends existing regulations to create a competitive bidding process specifically applicable to wind and solar project development. Currently, BLM regulations only provide for competitive bidding where there are “competing applications for the same facility or system.”[4]  Under the new regulations, the BLM will be able to use a competitive bidding process to open new lands to wind and solar project development, with the winning bidder becoming a preferred applicant for the right-of-way to the project site.[5]

Incentives

To incentivize bidding within DLAs, the proposed rule includes, among other incentives:

  • Reduced application fees, with a $5 per acre “nomination fee” within DLAs, as opposed to a $15 per acre application fee outside DLAs.
  • Streamlined processing and environmental review of projects within DLAs.
  • A 30-year fixed lease term within DLAs. Leases outside DLAs are available for up to 30-years, subject to adjustable terms and conditions.
  • A 10-year phase-in of the MW capacity fee, outlined below, rather than a three-year phase-in for facilities outside DLAs.
  • Standard bonding requirements of $10,000 per acre and $20,000 per acre for solar and wind energy developments, respectively. Outside DLAs, the bond requirement is based on the reclamation cost estimate minimum bond.[6]

Rent and Fees

Updated annual rent schedules are provided for in the proposed rule. These schedules are based on the approved acreage for the development, with a 10 percent encumbrance value for wind projects and a 100 percent encumbrance for solar projects.[7]

MW Capacity Fee

Additionally, the proposed rule establishes a MW capacity fee, based on the approved project MW, average wholesale energy prices, the federal rate of return per a 20-year treasury bond, and the project’s capacity factor, set at:

  • 20 percent for solar photovoltaic,
  • 25 percent for concentrated solar power,
  • 30 percent for concentrated solar power plus storage, and
  • 35 percent for wind.[8]

BLM explains that the MW capacity fee is intended to “capture the increased value of a solar or wind energy project on the public lands above the rural land value captured by the acreage rent.”[9]

BLM is implementing the wind and solar energy development rules pursuant to the President’s Climate Action Plan, announced in 2013, which uses “existing authorities to reduce carbon pollution, increase energy efficiency, expand renewable and other low-carbon energy sources and strengthen resilience to extreme weather and other climate impacts.”[10]

Since 2009, the BLM has approved an aggregate capacity of over 9,700 MW in solar, 4,700 MW in wind, and 600 MW in geothermal projects, for a total of approximately 15,000 MW of renewable energy.[11] In 2016 and 2017, BLM expects to review proposals for seven renewable energy projects, including five solar and two geothermal, with generation capacity of approximately 1,300 MW.[12]

We will continue to track this issue, and will report back with readers once the proposed rule has been finalized.

[1] 79 Fed. Reg. 59,022 (Sept. 30, 2014).

[2] Id.

[3] Id. at 59,022-023.

[4] Id. at 59,024.

[5] Id.

[6] See BLM, Competitive Solar and Wind Energy Leasing Regulations, available at http://www.blm.gov/style/medialib/blm/wo/MINERALS__REALTY__AND_RESOURCE_PROTECTION_/energy/solar_and_wind.Par.70101.File.dat/Public%20Webinar%20Dec%203%202014%20-%20Solar%20and%20Wind%20Regulations.pdf.

[7] 79 Fed. Reg. at 59,023.

[8]  Id.

[9] Id.

[10] BLM Press Release, Secretary Jewell Announces Competitive Leasing Policy to Encourage Solar and Wind Energy Development on Public Lands, Create Greater Certainty for Developers, Sept. 25 2014, available at http://www.blm.gov/wo/st/en/info/newsroom/2014/september/nr_09_25_2014.html.

[11] See BLM, Renewable Energy Projects Approved Since the Beginning of Calendar Year 2009, available at http://www.blm.gov/wo/st/en/prog/energy/renewable_energy/Renewable_Energy_Projects_Approved_to_Date.html.

[12] See BLM, 2016-2017 Renewable Energy Projects, available at http://www.blm.gov/wo/st/en/prog/energy/renewable_energy/2014-15_Renewable_Energy_Projects.html.

California Continues Ambitious Regulation of Greenhouse Gas Emissions

Yesterday, Governor Jerry Brown signed Senate Bill (SB) 32 into law, extending and expanding California’s 10-year old greenhouse gas (GHG) emissions reductions mandate under Assembly Bill (AB) 32.  SB 32 provides for a 40% reduction in GHG emissions from 1990 levels by 2030.  This builds on AB 32’s existing mandate to reduce statewide emissions to 1990 levels by 2020.  In negotiations to pass SB 32 in the final weeks of the state legislative session, the bill was trimmed to add only one sentence to existing statute, to insert the 2030 target.  Left unaddressed was one question of the moment, can the cap and trade program authorized by AB 32 legally continue past 2020?  The California Air Resources Board (ARB) has its own answer to the question, the subject of this earlier post.  The courts will no doubt end up as the final arbiter.  Whether post-2020 GHG emissions reductions are met through a cap and trade program or other screws and hammers in ARB’s toolbox, the 2030 target is now written into law, rather than just Executive Order B-30-15.

The vital component of the compromise to pass SB 32 was companion bill AB 197.  AB 197 establishes legislative oversight of ARB’s actions to implement AB 32 and SB 32, by creating a Joint Legislative Committee on Climate Change Policies and adding two ex officio nonvoting members to the Board.  AB 197 also puts a new twist on ARB’s broad authority to adopt rules and regulations to achieve emissions reductions.  AB 32 requires ARB to achieve maximum technologically feasible and cost-effective emissions reductions from sources or categories of sources.  AB 197 further requires ARB to prioritize direct emissions reductions, including from large stationary sources and mobile sources, when adopting rules and regulations to achieve reductions.

In addition to headliner SB 32, the Legislature passed one additional bill with direct emissions reduction mandates, SB 1383.

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