ITC Prepares to Vote on the Suniva/SolarWorld proceeding re Crystalline Silicon Photovoltaic Cells

As we approach the critical September 22  vote of the U.S. International Trade Commission (ITC) for the U.S. solar industry, here is a brief review of how we arrived at this point and what to expect.  This vote will constitute the injury determination in the ITC global safeguard investigation into the effect of imported crystalline silicon photovoltaic (CSPV) products on the U.S. domestic solar manufacturing industry.


As reported widely in the solar industry press, on August 15, 2017, the ITC in Washington D.C. conducted a public hearing for the injury phase of the trade investigation (Inv. No. 201-075) into CSPV product imports.  The hearing generated more than 400 pages of hearing transcript and thousands of pages of briefing materials and statements submitted both in support and in opposition of the need for trade protection remedies to  support the U.S. domestic solar manufacturing industry.  A public version of some hearing testimony is available here.  The stakes are high.  This investigation could lead to  increased tariffs, quotas, or both, against all U.S. imports globally of CSPV cells whether or not partially or fully assembled into other products. CSPV cells are the most common form of raw power-generating material used in solar panels.  This investigation is being conducted pursuant to U.S. trade statutes and U.S. obligations under the World Trade Organization (WTO) terms of the Agreement on Safeguards. Continue Reading

What is FPA Section 203(a)(1)(B)? American Transmission Company Reminded Us.

The US Treasury will soon be $205,000 richer due to the payment of a civil penalty by American Transmission Company (ATC) related to violations of sections 203 and 205 of the Federal Power Act.  ATC’s compliance failure stems from 21 transactions for which it had failed to file for authorization under section 203 and 29 agreements that ATC failed to file under section 205.  Without diving into the details of the individual transactions or agreements, what is clear to this observer is that ATC stumbled over two oft-misunderstood (and in one case, seldom-used) sections of the Federal Power Act and how they apply to these situations.

To begin, Section 203(a)(1)(B) requires that a public utility must obtain FERC’s prior approval before it “merge or consolidate, directly or indirectly, such facilities or any part thereof with those of any other person, by any means whatsoever.”  (I know–exciting!)  This rarely-used subpart of section 203 has generally been known as the “acquisitions section” and it requires a public utility to obtain FERC approval before acquiring the jurisdictional facilities of another public utility.  At least one of ATC’s acquisitions had a price tag of slightly over $1,000, but that didn’t matter here as there is no value threshold for section 203(a)(1)(B).  Any transaction, no matter how small, can trigger it (as ATC discovered).  The lesson to be learned here is that section 203(a)(1)(B)’s “merge or consolidate” language doesn’t mean exactly just that; it means “acquire.”

ATC’s second misstep was caused by the failure to file 29 agreements under section 205.  The energy industry is closely familiar with section 205 but primarily with respect power sales and transmission services.  In ATC’s case, it failed to file Common Facility Agreements for the shared use of substations and agreements to share transmission poles by double circuiting.  (Yes, they fall under FERC’s jurisdiction.  Surprise!)  These agreements are anything but your typical everyday contracts that one would expect to trigger section 205, and unfortunately there has been little clarity, if any, from FERC over the past decades regarding how section 205 may apply on its margins.

The penalty’s $205,000 amount is surprising given the nature of the violations, and it is made even more so given that ATC self-reported its violations to FERC.  (Not exactly encouraging for those considering it.)  But, on the positive side, we can all thank FERC’s Office of Enforcement (at ATC’s expense) for reminding us about these lesser-known applications of federal law.

California Extends Cap-and-Trade Through 2030

On July 25, 2017, California Governor Jerry Brown signed legislation extending the state’s cap-and-trade program through 2030. The signing ceremony for Assembly Bill (AB) 398 included former California Governor Arnold Schwarzenegger, who signed the first state statute authorizing cap-and-trade in 2006, AB 32.  The ceremony cemented the deal that Governor Brown struck with California lawmakers, passing AB 398 with bi-partisan support and a two-thirds majority of the Legislature.  In contrast to the passage of Senate Bill 32 in 2016, which extended California’s greenhouse gas reduction (GHG) targets through 2030 with the enactment of one simple sentence into statute, AB 398 stretched for pages.  AB 398 provided many details to be incorporated into the cap-and-trade regulation by the California Air Resources Board (ARB), the agency in charge of implementing cap-and-trade, and laid out requirements to mitigate the impacts of GHG regulation on regulated industry and increase in-state benefits.

Among the more note-worthy provisions of AB 398 were (1) a price ceiling on cap-and-trade allowances, (2) limitations on the use of offsets, particularly from out-of-state projects, and (3) a continuation of previous allowance allocations to vulnerable industries. ARB will also report to the Legislature by the end of 2025 on statutory changes needed to reduce leakage, including a potential border carbon adjustment.  Outside of the cap-and-trade regulation itself, the bill provides support to regulated entities with relief from sales and use taxes and prohibits local air districts from enacting additional GHG emissions reduction requirements.

In crafting the AB 398 deal, proponents of the bill wisely secured the votes necessary to pass the bill with a two-thirds majority and avoid the question whether cap-and-trade auctions post-2020 would be an unlawful tax under Proposition 26. The most recent cap-and-trade litigation in California Chamber of Commerce v. ARB and Morning Star Packing Co. v. ARB avoided this question, given that the original statute authorizing cap-and-trade, AB 32, was passed before Proposition 26 was voted in.  Proponents also secured support from sources as disparate as the California Chamber of Commerce, California Manufacturers and Technology Association, Natural Resources Defense Council, and Environmental Defense Fund.  Nevertheless, I would not rule out further judicial tangles on the implementation of AB 398 with amendments to the cap-and-trade regulation. Continue Reading

MN PUC Establishes New Environmental Costs for Use in All Proceedings

Today, the MN PUC concluded a nearly four-year effort on updating environmental costs established under section 216B.2422 subd. 3 of the Minnesota Statutes.  Before getting to the decision, a bit of context.


Under section 216B.2422, the MN PUC is required to, “to the extent practicable, quantify and establish a range of environmental costs associated with each method of electricity generation. A utility shall use the values established by the commission in conjunction with other external factors, including socioeconomic costs, when evaluating and selecting resource options in all proceedings before the commission, including resource plan and certificate of need proceedings.”  This statute was enacted in 1993, with the MN PUC first establishing final values in 1997.  Minor updates occurred after that time.  On October 9, 2013, the Izaak Walton League of America – Midwest Office, Fresh Energy, the Sierra Club, the Center for Energy and Environment, the Will Steger Foundation, and the Minnesota Center for Environmental Advocacy, filed a motion with the MN PUC request it to update the cost values for CO2 and NOx emissions, to establish a cost value for PM2.5, and to reestablish a value for SO2.  On February 10, 2014, the MN PUC granted the motion and reopened the investigation.  Significant debate, discussions, and litigation ensued, with the MN PUC ultimately breaking the contested case proceeding into two phases.  In Phase I, the MN PUC directed the parties to assess whether the Federal Social Cost of Carbon (FSCC) is reasonable and the best available measure to determine the environmental cost of CO2 and, if not, what measure would be better supported by the evidence.  In Phase II, the MN PUC directed parties to analyze and offer appropriate values for PM2.5, NOx, and SO2.

Now, on to the decision.  The MN PUC decided both phases, as described below, in an oral decision today.  A written order will follow.

Phase I:

The MN PUC established a new range of $9.05/short ton to $43.06/short ton.  Although the MN PUC did not accept the FSCC as a proxy for environmental cost for CO2 under Minnesota law, it did utilize modeling from the Interagency Working Group, with minor modifications to certain economic framing assumptions.  These modifications include using a range of 3% to 5% for a discount rate (and excluding 2.5%) and using a time horizon for damages from the year 2100 (for the low end of the range) to the year 2300 (for the high end of the range).

Because these values are used in various resource plan and resource acquisition proceedings, which involve decisions on utility investments, the MN PUC reaffirmed a prior decision to incorporate a $0 value input for modeling purposes to provide it with a fuller picture.

Phase II:

Three general geographies are currently utilized for the environmental cost values; rural, metro-fringe, and urban.  The MN PUC updated the ranges in Phase II as follows, assuming metro-fringe values: PM2.5 ($6,450 /short ton – $16,078/short ton); NOx ($2,467/short ton – $7,336/short ton); and SO2 ($4,543 /short ton – $11,317/short ton).

Concluding Thoughts:

Ultimately, it is difficult to state precisely how these new values will influence future proceedings, including resource planning and resource acquisition proceedings. These values will be one of many factors before the MN PUC in those future proceedings, including qualitative factors such as socioeconomic impacts and grid reliability impacts of any decision. But all of the new values are a significant increase from the current values.  And the new values will undoubtedly provide the MN PUC with a fresh look at the impact at the range of environmental costs associated with each method of electricity generation.

Another Court Upholds a State Generation Program and Dismisses Challenges to Illinois’ Nuclear Subsidies

On July 14, 2017, and several weeks after the Second Circuit rejected challenges to Connecticut’s renewable energy procurement process and renewable energy credit program (see Allco Fin. Ltd. v. Robert J. Klee (Docket Nos. 16-2946, 16-2949)), the U.S. District Court for the Northern District of Illinois dismissed challenges brought by independent power producers and customers against Illinois’ nuclear subsidy program (Village of Old Mill Creek v. Anthony M. Star, Docket Nos. 17 CV 1163, 17 CV 1164). This Illinois decision further support the authority of states to promote generation of their choosing and represents another narrow reading of the Supreme Court’s recent ruling in Hughes v. Talen Energy (136 S. Ct. 1288 (2016)).

In the state program at issue in Old Mill Creek, Illinois created a “zero emission credit” (ZEC), a tradeable credit (modeled after a renewable energy credit) which represents the environmental attributes of one megawatt hour of energy from specified zero emission facilities (in this case, selected nuclear power plants interconnected with the Midcontinent Independent System Operator (MISO) or PJM Interconnection (PJM)). The effective purpose of this program is to subsidize Exelon’s Clinton and Quad Cities nuclear facilities in Illinois, which Exelon had threatened to shut down if it did not receive government support. Continue Reading

Massachusetts Sets 200MWh Energy Storage Mandate

Massachusetts recently became the latest state to adopt an energy storage target, following California’s lead, and recent storage legislation in Nevada and New York.

The Massachusetts storage mandate originated in the legislature last year, when the state legislature passed H.4568, which was signed by the Governor on August 8, 2016. The legislation required the state’s Department of Energy Resources (DOER) to determine by December 31, 2016 whether to set targets for electric companies to procure viable and cost-effective energy storage systems to be achieved by January 1, 2020.  If DOER determined that targets were appropriate, then the storage targets were to be adopted by July 1, 2017.

DOER determined the targets to be appropriate, and adopted those targets one day before the July 1, 2017 deadline. DOER adopted a storage target of 200 megawatt-hours, to be achieved by January 1, 2020.

Massachusetts is following a path similar to California, which passed legislation (AB 2514) in 2010 directing the California Public Utilities Commission (CPUC) to consider adopting energy storage procurement targets. In October 2013, the CPUC adopted an energy storage target of 1,325 megawatts for the state’s three largest investor-owned utilities.  The storage must be installed by the end of 2024, and procured through four biennial procurements which commenced in 2014.

In 2015, Oregon adopted an energy storage mandate requiring Portland General Electric and PacifiCorp to procure a minimum of 5 megawatts of energy storage by January 1, 2020. New York also recently passed bills that directed the state’s Public Service Commission to develop a storage procurement target for 2030.

Court Rejects Preemption and Dormant Commerce Clause Arguments and Upholds Connecticut’s Renewable Program

On June 28, 2017, the U.S. Court of Appeals for the Second Circuit rejected challenges to Connecticut’s renewable energy procurement process and renewable energy credit program (Allco Fin. Ltd. v. Robert J. Klee (Docket Nos. 16-2946, 16-2949)). In doing so, the Second Circuit preserved the flexibility of states to enact programs to support renewable energy and became the first federal court to apply the Supreme Court’s ruling in Hughes v. Talen Energy (136 S. Ct. 1288 (2016)). While the Second Circuit’s decision raises some questions about the boundaries of state renewable energy programs, its narrow reading of Hughes v. Talen Energy supports a wide range of state renewable energy programs.

Allco (a renewable energy developer that participated, but was not selected, in Connecticut’s renewable energy procurement process) petitioned the court to overturn Connecticut’s renewable program on preemption grounds. Under Connecticut’s renewable energy procurement process, Connecticut solicits proposals for renewable energy through a competitive solicitation, and then Connecticut’s utilities are directed to enter into power purchase agreements for energy, capacity and environmental attributes with the solicitation winners. In its complaint, Allco argued that, since the Federal Power Act (FPA) grants the Federal Energy Regulatory Commission (FERC) exclusive jurisdiction over wholesale sales of electricity, the FPA preempts any action taken by states dealing with wholesale electricity sales (outside of the Public Utility Regulatory Policies Act (PURPA) and the regulations that apply to qualifying facilities (QFs)). According to Allco, Connecticut’s renewable energy procurement process compelled a wholesale power transaction, similar to what the Supreme Court struck down in Hughes v. Talen Energy (in which Maryland guaranteed selected generators a fixed capacity price for participating in a FERC-approved capacity auction). Continue Reading

California Supreme Court Denies Request to Review Cap-and-Trade Case

Yesterday the California Supreme Court denied a petition for review of the cap-and-trade lawsuits brought by a coalition of business interests, headed by the California Chamber of Commerce and Morning Star Packing Company. The Court of Appeal decision issued in April 2017, which upheld the legality of California’s cap-and-trade auctions in the related cases California Chamber of Commerce v. California Air Resources Board and Morning Star Packing Company v. California Air Resources Board, will thus stand.

With the California Supreme Court’s decision on the petition for review, the legal pall overshadowing the cap-and-trade auctions has dissipated, but questions still abound on the future (and legality) of the cap-and-trade program after 2020. Several cap-and-trade bills introduced in the California Legislature this session failed to meet key deadlines to come up for a vote in 2017, though California Governor Jerry Brown is pursuing efforts to reach an agreement among California legislators to amend AB 32 to explicitly extend the cap-and-trade program post 2020 by statute.  Draft amendments to the cap-and-trade regulation, including to continue the program through 2030, are pending at the California Air Resources Board, but the Board intends to first vote on the AB 32 Scoping Plan Update before turning to cap-and-trade amendments.  The Board delayed consideration of the Scoping Plan Update from its June 22, 2017 meeting and has not yet re-calendared this item.  Without a clear statutory mandate for cap-and-trade to remain in effect after 2020, new lawsuits are likely to be filed.

Updates to Energy Related Bills in the 2017-2018 California Legislative Session

Stoel Rives’ Energy Team has been monitoring and providing summaries of key energy-related bills introduced by California legislators since the beginning of the 2017-2018 Legislative Session. June 2, 2017 was the deadline by which the legislature was required to pass bills out of the house of origin.  Failing to meet that deadline does not automatically prevent a bill from proceeding through the legislative process; however, such failure will prevent the bill from being considered by the full legislature or the Governor during the first half of the Legislative Session.  Below is a summary of bills we have been following that have most recently changed.  We will continue to monitor and update these energy-related bills as the legislative session proceeds.

Assembly Bills

AB 79 (Levine, D): Electrical generation: hourly greenhouse gas emissions: electricity from unspecified sources.
STATUS: Ordered to Senate June 1, 2017.

  • Initially introduced as a bill to decrease the amount energy consumed from coal-fired generation resources, AB 79 was revamped to require, by January 1, 2019, the State Air Resources Board (CARB), in consultation with the Independent System Operator (ISO), to regularly update its methodology for the calculation of emissions of greenhouse gases associated with electricity from unspecified sources. The bill would require the CPUC and the CEC to incorporate the methodology into programs addressing the disclosure of the emissions of greenhouse gases and the procurement of electricity by entities under the respective jurisdiction of each.

Continue Reading

California Agencies Hold En Banc on Retail and Customer Electricity Choice

On May 19, 2017, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) held a joint en banc on customer and retail choice in California. In attendance were CPUC Commissioners Guzman Aceves, Randolph, Peterman, and President Picker.  CEC Commissioners McAllister, Douglas, and Chair Weisenmiller attended.

The en banc was intended to address a seismic shift in the entities serving load in California. As noted in the CPUC Staff White Paper issued in connection with the en banc meeting, by the end of this year, as much as 25% of the retail load served by the investor-owned utilities (IOU) will obtain their electric generation service from an entity other than an IOU.  Some estimates project that by the middle of the 2020s, over 85% of retail load may be served by sources other than the IOUs.  These changes are driven by the explosive growth of both distributed generation, primarily rooftop solar, and Community Choice Aggregation (CCA).  Direct access customers also comprise a significant portion of the retail load served by non-IOUs.

California has been extremely successful in pursuing its greenhouse gas reduction goals and expanding renewable energy procurement in the electricity sector. The question arises, however, as to how California will continue to pursue these goals under a scenario where 85% of the retail load is served by entities other than IOUs, whose current procurement decisions are not reviewed or approved by the CPUC, unlike the IOUs.  How will California pursue its greenhouse gas reduction goals, while maintaining reliability and affordability, especially for low and middle income residents, under a regulatory and procurement regime that is far less centralized than the regime that resulted in California’s current successes?  The Commissioners acknowledged that they will need to examine the current business models for load-serving entities and determine whether they can achieve the state’s ultimate goals.

Among the topics discussed at the en banc was the issue of exit fees. In order to comply with California’s Renewable Portfolio Standard (“RPS”) mandate, IOUs procured renewable energy under power purchase agreements that are priced much higher than the current market.  As the IOUs’ retail load decreases, their RPS obligations similarly decrease, potentially leaving IOUs with highly-priced RPS contracts that are in excess of their RPS mandate.  Under the statute, implementation of a CCA cannot result in cost shifting between CCA customers and those customers choosing to remain with the IOU.  Thus, as these contracts were procured to serve customers who are now migrating to CCAs, arguably those costs should follow customers.  Other issues arise from potential “double procurement,” where CCAs procure renewable power for the same customers that IOUs have already signed long-term RPS contracts to serve.

The en banc consisted of four panels–a customer panel; a provider panel, consisting of distributed generation providers, direct access providers, and CCAs; a utility panel, and an industry expert panel. Though no clear answers emerged, the Commissioners will take the input from the meeting back to their respective Commissions as they address current and future proceedings dealing with the rapid expansion of retail choice.