FERC Revises Delegation Authority While It Lacks a Quorum

Today is Commissioner Norman Bay’s last day on the job at the Federal Energy Regulatory Commission (FERC), which means that on Monday, FERC will no longer have the quorum of 3 commissioners that is necessary for it to do much of its business.  (Two other vacancies have gone unfilled for months.)  Earlier today, Acting Chairman Cheryl LaFleur announced that the authority normally delegated to FERC Staff has been modified so that some business may continue until a quorum is re-established.  The order on delegated authority becomes effective tomorrow, February 4, 2017, and will remain in place until shortly after new commissioners arrive at FERC (which requires Senate confirmation).  Staff’s temporary delegated authority is as follows:

  • Rate and other filings: The Director of the Office of Energy Market Regulation (OEMR) can accept and suspend rate filings, and make them effective subject to refund and further order of the Commission, or accept and suspend them, make them effective subject to refund, and set them for hearing and settlement judge procedures. For initial rates or rate decreases submitted under section 205 of the FPA, for which suspension and refund protection are unavailable, FERC staff is granted authority under section 206 to institute proceedings in order to protect the interests of customers.
  • Extensions of time: FERC staff can extend the time for action on matters where it is permitted by statute.
  • Waiver requests: The Director of OEMR can take appropriate action on uncontested filings under the NGA, FPA and ICA, seeking waivers of the terms and conditions of tariffs, rate schedules and service agreements, including waivers related to capacity release and capacity market rules.
  • Uncontested settlements: The Director of OEMR has authority to accept settlements not contested by any party or participant, including Commission trial staff.

But despite these revisions to Staff’s delegated authority, much of the business before FERC will await a quorum.   And with the apparent priorities in the White House and in Congress these days, we may be waiting a while for FERC to resume business as usual.

Wyoming: Partying Like It’s 1899

Wyoming has one of the nation’s best wind resources.  But if a contingent of state senators and representatives there have their way, electric utilities located in the state will be slapped on the wrist for using it (or other renewables, for that matter).  Senate File 71, which has been introduced in the Wyoming State Senate and was referred to the Corporations Committee this week, would impose an “Electricity Production Standard” on the state’s electric utilities, requiring them to procure 95% of the energy used for load from “eligible generating resources” in 2018 and 100% in 2019.  The catch is that “eligible generating resources” are limited to coal, hydro, natural gas, net metering (limited to 25 kW), nukes, and oil.  Wind, solar, geothermal, etc. are mysteriously absent…  The legislation would also cause electric utilities to demonstrate their compliance through “energy credits” obtained from “eligible generating resources”–“not-RECs” perhaps?–and shortfalls could cost utilities a penalty of up to $10/MWh.

And Wyoming is not the only state where wind energy is under attack.  A North Dakota state legislator is proposing to impose a “$1.50/MWh generated” tax on wind farms, as well as an additional tax equal to 10% of the production tax credit.  Representative Roscoe Streyle describes the proposal as leveling the playing field for coal.

One step forward, a century of steps back.

California Cap-and-Trade Lawsuit Hits Milestone with Oral Argument at the Court of Appeal

Yesterday, California’s Third District Court of Appeal heard oral argument in the related cases California Chamber of Commerce v. California Air Resources Board and Morning Star Packing Co. v. California Air Resources Board.  The three-justice panel actively questioned both sides as lawyers for the State, the Chamber, Morning Star, and Environmental Defense Fund made their arguments.  One news outlet has forecast the justices’ leanings, based on the questions asked.  As arguments were heard, across the street in the Capitol, Governor Brown highlighted in the annual State of the State address California’s actions to reduce greenhouse gas emissions.  While the pending CalChamber/Morning Star lawsuit is important, it is only one of several moving parts in play this year affecting greenhouse gas regulation in California.  SB 32, effective January 1, 2017, extends and deepens the state’s greenhouse gas reduction goals to 40% below 1990 emission levels by 2030, codifying Governor Brown’s Executive Order No. B-30-15.  But SB 32 is silent on cap and trade, and the question of whether AB 32 — the original statutory greenhouse gas reduction mandate enacted in 2006 — authorizes cap and trade past 2020 (see the Legislative Counsel’s letter) means that additional legal challenges to the cap and trade regulation are virtually guaranteed unless legislation clears up the ambiguity.  To that end, in his recent budget proposal, Governor Brown called for urgency legislation to confirm the Air Resource Board’s authority to continue cap and trade beyond 2020.  If passed by the Legislature as an urgency measure, the bill would be adopted with a two-thirds supermajority.  This would moot going forward the main contention before the Court of Appeal – that cap and trade auctions authorized under AB 32 constitute an unconstitutional tax, passed without the requisite legislative supermajority.  Meanwhile, the Air Resources Board is moving forward with implementation of SB 32 and the extension of cap and trade through 2030, with the release of the draft 2017 Climate Change Scoping Plan Update on January 20, 2017 and a vote expected on cap and trade amendments in the spring.  As for the fate of allowance auctions under the current cap and trade program, we’ll have a decision from the Court of Appeal within 90 days.  Regardless of the outcome, expect an appeal to the California Supreme Court, keeping this piece of the California greenhouse gas puzzle in play.

While Washington DC Wrestles with Ratings, Massachusetts Proposes 100% Renewables by 2035/2050

Amidst all the focus in Washington DC over inauguration crowd sizes, at least one state is instead focusing on matters affecting jobs, security, and quality of life–renewable energy!  A bill (SD.1932) introduced in Massachusetts would require the state to use 100% renewable energy for electricity by 2035 and also seeks to deeply cut fossil fuels from the heating and transportation sectors as well.  The proposed bill, which is sponsored by Representatives Garballey, Decker, and Eldridge, would require the transportation sector to use 50% renewable energy by 2030, and would cause the state to use 100% renewable energy by 2050 for all energy usage, “including the energy consumed for electricity, heating and cooling, transportation, agricultural uses, industrial uses, and all other uses by all residents, institutions, businesses, state and municipal agencies, and other entities operating within its borders.”   The sponsors describe the bill as creating jobs and providing energy security.  The proposed bill is available here.

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.