Transaction Structuring Matters: North Carolina Rejects Third-Party Rooftop Solar Power Purchase Agreements

A North Carolina appeals court has reminded energy developers in the state of the importance of structuring a transaction so as not to trigger the state’s utility franchise laws. For one unfortunate developer, that reminder came in the form of disgorged revenues and potential monetary penalties.

Earlier this month, on September 19, 2017, a North Carolina appeals court (in a 2-1 decision) upheld a decision of the North Carolina Utilities Commission (“NCUC”), which found that an environmental non-profit organization (NC WARN) was impermissibly operating as a North Carolina “public utility” when NC WARN entered into a power purchase agreement to own and operate solar panels on a church’s property and to charge the church based on the amount of electricity generated by the solar panels. (State of North Carolina ex rel. Utilities Commission et al. v. North Carolina Waste Awareness and Reduction Network, Case No. COA16-811). The North Carolina court found that such service by NC WARN infringed on the franchised utility’s electric service territory, contrary to North Carolina’s policy prohibiting retail electric competition and establishing regional monopolies on the sale of electricity. According to the court, NC WARN’s activities (in owning and operating the solar panels on the church’s roof and selling electricity from those solar panels to the church) were in direct competition with the franchised utility’s services as both entities were selling electricity to the franchised utility’s customer.   Continue Reading

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. Legislators have been busy moving bills through the legislative process since reconvening from the Summer Recess. For any bill not identified as a two-year bill, the deadline for each house to pass the bill and present it to the Governor for signature or veto was September 15, 2017. Below is a summary and status of bills we have been following.

An enrolled bill is one that has been through the proof-reading process and is sent to the Governor to take action. A two-year bill is a bill taken out of consideration during the first year of a regular legislative session, with the intent of taking it up again during the second half of the session.

  • Of particular note here is SB 100, California’s pitch for 100 percent renewable energy, failed to move to the next stage of the process and is kicked to next year.
  • Our next blog post, after October 15, will provide an update on whether those bills sent to Governor Brown were signed or vetoed.

Continue Reading

Recent Federal Actions to Streamline the NEPA Process

There has been a string of actions in the past few weeks addressing the federal government’s policy goal of streamlining the NEPA review process.  Although a number of actions have been taken, it presently boils down to this:  the federal government seems to genuinely be pursuing ways to make the NEPA process for infrastructure projects (including energy projects) faster, more predictable, and more efficient.  Whether and how this will be implemented in practice remains to be seen.  The Dept. of Interior and CEQ have been the first to take (aspirational) actions to implement this policy.  The following summarizes the recent actions.

President Trump issued Executive Order 13807, titled “Establishing Discipline and Accountability in Environmental Review and Permitting Process for Infrastructure Projects. Among other things, EO 13807 directs the following:

  • Development of a “performance accountability system” to track milestones and deadlines “major infrastructure projects,” score agencies’ ability to meet those deadlines, establish best practices for the permitting/review of infrastructure projects.  Projects would also be tracked through a “dashboard” that is updated monthly.
  •  Implement “One Federal Decision” for major infrastructure projects.  Under “One Federal Decision,” a project would have a single lead agency that will coordinate all necessary federal approvals and issue a single record of decision to address all those approvals.
  • The completion of all permit decisions should occur within 90 days of the ROD, and “not more than an average of approximately 2 years” after issuance of the notice of intent to prepare an EIS.
  • CEQ’s development of a list of initial actions that it will take to modernize the federal environmental review process, which can include issuing new regulations, guidance, and other directives.

For purposes of the EO, “major infrastructure project” essentially includes energy, water, and transportation projects for which multiple federal authorizations are required and for which an EIS is required.  The EO is fairly general and ambiguous and leaves room for exceptions to just about all of its directives.  The EO can be viewed here:

CEQ responded by issuing a notice listing the actions it plans to take to implement EO 13807, as follows: Continue Reading

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