SEPA Selects “Grid Market Structures” Paper Concept as a Focus of 51st State Summit

I’m pleased to announce that the Solar Electric Power Association has selected a paper authored by James Tong of Clean Power Finance, Jenny Hu and myself as one of three concepts that will focus discussion at SEPA’s 51st State Summit on Monday, April 27 in San Diego. Titled “The 51st State: Market Structures for a Smarter, More Efficient Grid,” the paper was selected from a dozen submitted by individuals and organizations from across the country.

You can view our paper concept at this SEPA link (PDF). A screenshot of the abstract of our paper is available at the end of this post.

As Gavin Bade of Utility Dive described in a review of our paper concept last week, James, Jenny and myself are calling for an Independent Distribution System Operator (IDSO) model under which the grid  would operate like a network “not unlike the Internet, stock market, or our capitalistic economy,” with millions of actors each day making value-based energy decisions on a “plug-and-play” grid with multi-directional electricity flows. Continue Reading

Jon Wellinghoff Joins Blogger Team at Renewable + Law Blog

Hi there, this is Jon Wellinghoff, former FERC chair and current Stoel Rives partner. I’m pleased to announce that effective today I have joined the Stoel Rives Renewable + Law blogger team. We thought it would be useful to share with you blog readers some of my thinking and writing on the topic of energy policy and energy transformation.

We’re going to kick things off today with a review of my recent press commentary, op-eds and announcements. In the future, I also expect to review some individual cases that have particular importance for U.S. and global energy policy as well as for energy industry participants.

What’s Happening?

On March 31, 2015, I appeared in a Q&A with Robert Fares of the Scientific American Blog titled “Wellinghoff: Extend Electricity Market Visibility to the Distribution Grid.”

On March 30, 2015, the Center for Resource Solutions announced that I will be joining their board of directors. Joining me on the board is Karin Corfee of Navigant Consulting. Read the release:

On March 28, 2015, The Texas Tribune published a Q&A I had with Jim Malewitz titled “Wellinghoff: Texas Needn’t Fret Over Climate Rules.”

On March 25, 2015, James Tong of Clean Power Finance and myself published an op-ed in Utility Dive titled “Tong and Wellinghoff: Are fixed charges a curse in disguise for investor-owned utilities?”

On March 25, 2015 I was featured in a front cover USA Today story titled “Power Grid Left Open to Attacks.”

On March 6, 2015 I published an op-ed in the Washington Post titled “Clean power is right for Virginia.”

Where’s Jon?

I am scheduled to attend the following events and conferences in April:

Beginning on April 27, I will be the keynote speaker at Infocast’s Grid Transformation Summit in New York, NY. I will also present at the event in a presentation titled “Moving Beyond Smart – Making the Distribution Grid More Open, Resilient and Efficient.”

Beginning on April 30, Lisa Polk Edgar of NARUC and I will be keynote speakers at NEM’s 18th Annual National Energy Restructuring Conference, in Washington D.C.

USFWS Publishes Northern Long-Eared Bat Listing Decision, Opts for Interim 4(d) Rule

In a long-anticipated move, the U.S. Fish and Wildlife Service (“Service”)has published a final listing decision and interim rule on the northern long-eared bat. The Service listed the northern long-eared bat as threatened under the Endangered Species Act (“ESA”), 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 rule.

The effect of the interim 4(d) rule depends on the location of a particular activity. For areas of the country not affected by white-nose syndrome, the interim 4(d) rule exempts incidental take from all activities. For areas of the country affected by white-nose syndrome, the interim 4(d) rule exempts from ESA 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 protect known maternity roosts and hibernacula. These activities are exempted provided: (1) the activity occurs more than 0.25 mile (0.4 km) from a known, occupied hibernacula, (2) the activity avoids cutting or destroying known, occupied roost trees during the pup season (June 1–July 31), and (3) the activity avoids 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).

Importantly, due to the significant number of comments received in response to the 4(d) rule proposed on January 15, 2015, the Service has opened a 90-day comment and will accept further input on the interim rule through July 1, 2015. The Service has specifically asked for comments on “whether it may be appropriate to except incidental take as a result of other categories of activities beyond those covered in the proposed rule and, if so, under what conditions and with what conservation measures.” More information on the interim rule and opportunity to comment is available here.

Rep. Garofalo Posts Bold Minnesota Energy Omnibus Bill

Late this afternoon, Rep. Pat Garofalo posted a bold and significant omnibus bill on the web page for the Job Growth and Energy Affordability Policy and Finance Committee of the Minnesota House of Representatives.  This author has not gone through the bill in detail, but calls out the following provisions as noteworthy based on a quick review this afternoon:

  • Article 2: Changes related to energy conservation, including a December 31, 2016, sunset to the conservation improvement program, and corresponding creation of an energy conservation advisory taskforce with appropriation of funds for an energy technology business accelerator.
  • Article 3: Modifications related to renewable energy, including creation of an “advanced energy standard” that counts all hydroelectric generation as an eligible renewable technology in meeting an RPS increased by 2%; allowance for the solar energy standard to be met “through the use of solar energy or any other more affordable elligible energy technology;” creation of new siting and approval requirements for solar energy generating systems; modifications to the Made in Minnesota incentives; and a repeal of the Value of Solar subdivision in section 216B.164.
  • Article 4: Elimination of the 80% by 2050 greenhouse gas emissions goal and replacement of it with a continued goal of a general reduction in an affordable manner.
  • Article 5: Changes to general rate provisions, including an affirmative statement “to position Minnesota at the median among states with respect to energy rates;” establishment of a new performanced-based multiyear plan for utilities and competitive rate for energy-intensive trade-exposed customers (similar to e21 recommendations, coverage here); creation of a compressed natural gas vehicle rebate program; and direction to study the functions of the Department of Commerce – Division of Energy Resources, the low-income heating assistance programs, and the feasibility and potential costs and benefits of creating a state public power authority.

The Minnesota legislature will be on break next week, which will allow the bill some time to simmer before the legislature returns and takes these proposals up for discussion.  On March 19, the Senate Energy Committee voted out its omnibus bill.  Although there are similarities between the two bills, there are significant differences.  How these two pieces of proposed legislation proceed will be interesting to watch!

MN PUC Approves First Minnesota Multiyear Plan, But Work Remains on Implementation

Yesterday, the Minnesota Public Utilities Commission (the “Commission”) met to address the first general rate case filed under section 216B.16 subd. 19 of the Minnesota Statutes. Northern States Power Company, a Minnesota Corporation, d/b/a Xcel Energy submitted the multiyear rate petition on November 4, 2013. In that petition, Xcel Energy asked for an increase in retail electric rates in Minnesota of $192.7 million, or 6.9%, effective January 1, 2014, based on a forecasted 2014 test year, and a proposed return on equity capital of 10.25%. As part of its multiyear proposal, Xcel also asked for a calendar year 2015 step increase of $98.5 million, or 3.5%, effective January 1, 2015.  Over the last 500+ days, parties to the proceeding worked through the contested case process, addressing such issues as the revenue requirement, class cost of service study, and rate design.

On December 26, 2014, the Administrative Law Judge issued her Findings of Fact, Conclusions of Law, and Recommendations (“ALJ Report”). On January 16, 2015, Xcel Energy submitted a compliance filing noting that, if the ALJ Report were adopted in its entirety, Xcel Energy’s two-year rate increase would be reduced from $291.1 million to $191.3 million, based on a return on common equity of 9.77%.

The Commission did not adopt the findings and recommendation in the ALJ Report in their entirety. And given the complexity of the issues and their respective interrelationships, the impacts of all of the Commission’s decision yesterday on revenue requirement issues are not yet known. For example, the recent decisions regarding Monticello need to be folded in to the revenue requirement for 2014 and 2015 (coverage here). Another significant portion of yesterday’s decision relates to capital structure and return on equity. The Commission approved Xcel’s proposed capital structure comprised of 52.50% common equity, 45.60% long-term debt, and 1.90% short-term debt for 2014 and 52.50% common equity, 45.61% long-term debt, and 1.89% short-term debt for 2015. But the Commission adopted a hybrid ROE calculation that resulted in an return on common equity of 9.72%. The impact of the Commission’s resolution of other issues, such as pension, corporate aviation costs, will also need to be assessed.

With respect to class cost of service study issues, the Commission appeared to ignore concerns raised by the business community regarding Minnesota’s increasingly uncompetitive rates, rejecting proposed changes related to classification and allocation. Given that some of the changes were built into Xcel Energy’s filed class cost of service study, the Commission ordered that Xcel re-file its class cost of service study to incorporate the Commission’s resolution of various issues.

With respect to rate design, the Commission approved Xcel Energy’s proposed revenue decoupling mechanism (“RDM”), as a three-year pilot program. The Commission modified Xcel Energy’s proposal from a partial RDM to a full RDM and put a soft-cap limitation on the RDM billing rate increases. Xcel Energy is the first electric utility in Minnesota to receive approval of an RDM. A number of other rate design proposals were before the Commission, some of which were accepted and some of which were rejected. Notably, the Commission approved a proposal from a group of industrial consumers for a renewable energy purchase option – Xcel Energy was directed to work with customers to develop a tariff and bring it before the Commission for approval.

The Commission’s written decision will probably be issued in 3-5 weeks. Once received, Xcel Energy will have compliance filing work to complete, including revised schedules of rates and charges to reflect the Commission’s decision, a revised class cost of service study, and a proposal for addressing the interim rates that have been in effect since early 2014. Parties will have the opportunity to comment on these filings and submit petitions for reconsideration or clarification of the Commission’s decision.

MN PUC Denies Return on Cost Overrun for Xcel Nuclear Project

On Tuesday and Friday this week, the MN PUC heard arguments from various stakeholders regarding the Xcel Energy life cycle management and extended power uprate (LCM/EPU) projects. The stage for the arguments was set by the contested case proceeding and decision by an Administrative Law Judge (coverage here).

At Tuesday’s oral argument, the MN PUC asked Xcel Energy a number of difficult questions and conveyed its frustration with Xcel Energy’s handling of the LCM/EPU projects. After a year’s worth of proceedings, extensive testimony, a day of oral arguments and continued questioning yesterday morning, the MN PUC determined that “the information provided by Xcel lacks the transparency necessary to quantify the prudence of final costs.” The MN PUC also chastised Xcel Energy for its lack of communication regarding the cost overruns. Indeed, the MN PUC found that Xcel Energy “should have kept the Commission informed and given it the opportunity to timely review the increased expenditures and the reason for them.”

In light of these failures, the MN PUC spent significant time yesterday trying to arrive at an appropriate remedy. A number of proposals were before the MN PUC, ranging from a minor disallowance to a disallowance of approximately 75% of the cost overruns and no return on the remaining 25%. First, however, the MN PUC had to calculate the initial estimate for the LCM/EPU projects in 2014 dollars because even that wasn’t clearly set out in the record. The MN PUC determined that the initial estimate was $415 million in 2014 dollars, including AFUDC. The final cost of the LCM/EPU projects was $748 million, including AFUDC, resulting in a $333 million cost overrun. After significant debate, the MN PUC voted to approve recovery of that $333 million while at the same time denying a return on that portion of the investment. The impact of this decision is a reduction to the 2015 revenue requirement for the Minnesota jurisdiction of approximately $27 million, which will step down over the remaining life of the asset.

Another issue that was before the MN PUC was whether the EPU portion of the project was used and useful in the 2014 test year of the pending Xcel Energy rate case (the MN PUC will hear oral argument and decide all of the remaining issues in the rate case later this month). Given Xcel Energy’s continued regulatory difficulties and inability to utilize the full (or even a significant portion) of the 71 MW uprate for any extended period of time, the MN PUC found that the EPU investment was not used and useful in providing service to Minnesota ratepayers in 2014. As part of this decision, the Commission resolved the debate on what portion of the costs for the LCM/EPU projects were LCM-related and what portion were EPU-related by using a 50-50 split. The impact of these decisions has not been quantified, but will appear in a subsequent Xcel Energy compliance filing.

California State Senators Announce Legislation To Support Clean Energy and Reduce Greenhouse Gas Emissions

Yesterday, California legislators publicly announced a suite of bills to push forward the state’s ambitious clean energy and carbon reduction goals.  California Climate Leadership, a coalition of state senators, including Kevin De León, Ben Hueso, Mark Leno, Fran Pavley, and Bob Wieckowski, discussed the legislation at a press conference shown hereSB 350, SB 185, SB 189, and SB 32 form the core of California Climate Leadership’s legislative initiative.

SB 350, not yet formally introduced in the Senate, proposes the “Golden State Standards”:  a 50% renewable portfolio standard, a 50% reduction in petroleum use and a 50% increase in energy efficiency in buildings – all by 2030.  These standards parallel Governor Jerry Brown’s call in his inaugural address for a 50% RPS, 50% reduction in petroleum use, and doubling of energy efficiency of existing buildings by 2030.  See our report on the inaugural address here.  SB 350 will be the second bill this year that provides a 50% RPS; AB 197, summarized by Renewable + Law here, was introduced on January 28 by Assembly Member Eduardo Garcia.

SB 185 would create the Public Divestiture of Thermal Coal Companies Act.  The Act would require the California Public Employees’ Retirement System (CalPRS) and the State Teachers’ Retirement System (CalSTRS) to divest public employee retirement funds of any investments in thermal coal companies and prohibit new investments in such companies.  Senator De León previewed his plans for SB 185 in early December, spurring a backlash from CalPERS and CalSTRS. 

SB 189, introduced by Senator Ben Hueso, would create the Clean Energy and Low-Carbon Economic and Jobs Growth Blue Ribbon Committee.  The Committee would be comprised of seven members, with the mission of advising state agencies on the most effective ways to allocate clean energy and greenhouse gas related funds and implement policies in order to maximize California’s economic and employment benefits.

These three bills join SB 32, introduced by Senator Fran Pavley on December 1, 2014, to amend AB 32 (the California Global Warming Solutions Act) to bring California’s greenhouse gas reduction goal from reaching 1990 greenhouse gas levels by 2020, to a target of 80% below 1990 levels by 2050.

Stay tuned – we don’t expect these bills to be the last legislative initiatives this session to address these issues.

ALJ Recommends MN PUC Partially Disallow Xcel Energy’s $400 Million Cost Overrun on Monticello Project

Today marked the release of the highly anticipated report and recommendations from the Administrative Law Judge tasked with reviewing Xcel Energy’s handling of the life cycle management and extended power uprate (LCM/EPU) projects  The MN PUC initiated review of the LCM/EPU projects at the conclusion of Xcel Energy’s 2012 electric rate case after learning that the total costs of the LCM/EPU projects were approximately double Xcel Energy’s estimates utilized in the underlying certificate of need proceedings.  The thrust of the MN PUC’s inquiry was whether Xcel Energy’s handling of the LCM/EPU projects were prudent, whether the cost overruns were reasonable, and what disallowance remedy, if any, should be adopted.  As a necessary part of this analysis, the MN PUC directed the ALJ to determine what portion of the total $748 million spent on the LCM/EPU projects were for the LCM and EPU, respectively.

Relying heavily on analysis from the Minnesota Department of Commerce, the ALJ’s report questions Xcel Energy’s management of the LCM/EPU projects.  The ALJ ultimately concluded that “Xcel’s principal failure was that it did a very poor job managing the initial scoping and early Project management up until beginning installation during the 2009 refueling outage.  The Company’s decision to proceed with the combined LCM/EPU Project in 2009 rather than 2011 created an extremely difficult task that Xcel was not able to manage.”  The ALJ’s report goes on to chastise Xcel Energy for failing to appropriately track LCM and EPU project costs, proffer a reasonable cost allocation split for the LCM and EPU projects, and demonstrate a reasonable figure for disallowance.

The ALJ concluded that Xcel Energy’s failures justify a disallowance of approximately $72 million of the EPU project costs, resulting in a roughly $10 million reduction to Xcel Energy’s annual revenue requirement on a Minnesota Jurisdictional basis.  This reduction is based on a cost-effectiveness comparison between the final cost of the EPU against the cost of the next least-cost alternative that was considered in the underlying EPU certificate of need proceedings.

Parties to the proceeding will have the opportunity to submit exceptions to the ALJ’s report.  Although no deadline has been set yet, we suspect review of the matter will proceed swiftly.  Oral argument before the MN PUC on this matter has already been set for March 3, with deliberations and an oral decision to follow on March 6.  This schedule was previously set to allow the MN PUC to build the decision into deliberations on Xcel Energy’s pending 2013 electric rate case (set to conclude by March 26).

Bill Targeting 50% RPS Introduced in California Legislature

In his inaugural address earlier this month, Governor Brown, referenced several ambitious goals he would like to see accomplished over the next 15 years, including  increasing from one-third to 50 percent the amount of California’s electricity that must be derived from renewable resources. On January 28, 2015, a legislator joined in this ambitious goal setting, as Assembly Member Eduardo Garcia (D, District 56) introduced Assembly Bill 197, which focuses on renewable resources procurement.

Under California’s current Renewables Portfolio Standard (RPS) 33 percent of procured electricity must come from eligible renewable energy resources.  As currently drafted, AB 197 would require “electrical corporation, in a long-term plan, or local publicly owned electric utility, in a procurement plan, to adopt a long-term procurement strategy to achieve a target of procuring 50 percent of its electricity products from eligible renewable energy resources by December 31, 2030.” [underline added]

We will be watching closely the strategies pursued by the Governor and the legislature to achieve his goal of a 50 percent RPS in California.  In this space, we will track further action by the legislature and regulatory agencies regarding the push to 50 percent RPS.

Minnesota Community Solar Gardens Forecast: Partly Sunny with a Chance of Rain

Within days of its open on December 12, 2014, Xcel Energy’s Minnesota Community Solar Garden (CSG) Program had well over 300 MW worth of CSG applications submitted and by this writing nearly 430 MW.  The rush of significant application creates a question of “who’s in line first?”  That was the question before the Minnesota Public Utilities Commission (Commission) today.

As noted in our prior coverage, the Commission instructed the program to be “first-ready, first-served” and laid out specific instructions on the steps developers would need to take to complete applications and develop a garden in compliance with the program. These instructions were the result of substantial deliberation with interested parties and reflected in Xcel’s shiny new Tariff Section 9 governing the CSG Program.  The problem, however, is that any CSG  needs to interconnect to Xcel’s distribution system, and that process is governed by Xcel’s existing Tariff Section 10.  The interplay of these two tariff sections complicates the “who’s in line first?” issue by adding the question “which line?” Importantly, over 100 MW of applications destined for the CSG program were in line in the Section 10 interconnection queue before the CSG program opened last month.  A developer sought resolution of the two-queue issue from the Commission.

After considerable discussion, the Commission essentially decided the interconnection queue should follow the CSG program queue and directed as follows:

  • CSG applications will enter the appropriate Section 10 interconnection queue and be placed or reordered in this queue based on the date and time that Xcel determines the application to be complete under Section 9.
  • For any interconnection applications already studied that require additional engineering study due to changes in the interconnection queue positions, Xcel was directed to track the additional cost incurred by re-performing parts of the engineering study and bill applicants for the parts of the study that were required to be redone due to distribution system changes.

Although it was understandably difficult for the Commission to decide at what point an application should receive a spot in line, today’s decision vests more weight in Xcel’s completeness determination – previously a ministerial task.  Furthermore, the Commission left open how CSG developers that have invested money in furtherance of Section 10 interconnection applications will receive value for that investment if they move backwards in the Section 10 interconnection queue.

During deliberations the Commission also acknowledged that other issues are bound to percolate.  Stay tuned . . .