Tag Archives: solar

A cautionary tale to communities negotiating with energy project developers

The City of Davis signed a lease option agreement on March 24 with a start up solar development company headed by a former CEO of a large renewable firm. How the negotiation process reflected a lack of sufficient knowledge on the part of the City staff is instructive to other cities and counties about the need to be fully informed when a renewable project developer approaches them about land or power deals. In this case the City gave away the potential for gaining tens of millions of dollars.

The agreement was negotiated in a series of closed sessions starting December 17 and approved in a rush under the premise that the project faced an April 15 deadline for submitting its interconnection application to the California Independent System Operator (CAISO). The deal immediately unleashed a storm of outrage from many knowledgeable citizens (several who are appointed city commission members) and the City responded soon after with a press release and “Q&A” that did little to quell the uproar. Two City Councilmembers then wrote an additional defense of the deal. The City’s Utilities Commission voted 5-2 to recommend that the City Council rescind the agreement. A request to “cure and correct” under the Brown Act was then filed April 23 by a group of citizens (including me).

Ashley Feeney, City Assistant City Manager, claimed at the Utilities Commission special meeting April 22 that the BrightNight lease option agreement and term sheet have “favorable terms to the City.”  No doubt it’s favorable to the developer — a low-cost lease option and lease terms at the average rate for agricultural use for a multi-million dollar solar energy project with no strings attached. The staff’s naivete comes through a close reading of the entire agreement.

What are so many people missing that makes this project so favorable to the City as the Council and staff claim? While the process of signing the lease option agreement with the developer was (a) unnecessarily secretive, (b) precluded useful citizen input, and (c) likely violated state law in several ways— at its core, the agreement is simply a bad deal. The City either failed to carry out its due diligence, or was seriously misled by the developer, or both. As a result, the City likely gave away millions of dollars over the next 50 plus years, failed to guarantee any clean energy for the City and failed to protect the City fully at the end of the project life. While the City may desire local renewable power, the agreement lacks any real commitment to advance the City’s climate goals while gaining local benefits.

The agreement (1) underprices both the lease option and the lease prices relative the actual value to the developer, (2) lacks any guarantee of plant power being sold to Davis or VCEA, much less at favorable terms, (3) lacks appropriate protection that sufficient funds will be available to decommission the plant, and (4) forsakes opportunities for more valuable alternative uses for those parcels for at least the next five years.

The first of those misunderstandings was that there was, in fact, no need for the developer to have site control for the CAISO interconnection process.  Whatever developer’s “standard” practice is has no bearing on how and what the City should decide in its own interest. The CAISO interconnection process requires either (1) a $250,000 refundable deposit regardless of site control plus a $150,000 study deposit, if the project is submitting under the Cluster application which is due by April 15, or (2) with site control there is no deposit except the same $150,000 study deposit under the Independent Study Process and no deadline. In this case, the City has essentially gifted the developer $225,000 by providing site control at a steep discount. The developers appears to have exploited the City’s lack of knowledge about the interconnection process by conflating the two processes.

Instead the City should have priced the lease option to reflect the developer’s value, not the City’s. That means that handing over the site control was worth the avoided carrying cost of that deposit each year. With a standard rate of return of at least 10% on real estate investments, that amounts to $25,000 per year, which translates into $106 per acre.  In any case, the minimum opportunity cost to the City is either using it for annual row crop agriculture or reflecting the delay in other uses such as organic waste processing, both of which far exceed the $20 per acre in the lease option.

The City should have specified that the project sell output only to either the City or Valley Clean Energy Authority (VCEA) at a favorable price. The developer is now in the driver’s seat and can solicit bids from the entire range of utilities and load-serving entities such as PG&E, SMUD and other CCAs. This will make the cost of this power more expensive even if Davis or VCEA wins the power output. But now that the agreement has been executed, the City no longer has any leverage in either the lease terms or an energy sale to VCEA, because it cannot force the developer into an agreement.

The City could have specified that the output be wheeled to City accounts through PG&E’s RES-BCT tariff that is available to public agencies. A wholesale solar power contract for the project is unlikely to be much more than 5 cents per kilowatt-hour. In contrast, if the project was structured to take advantage of the the power savings under RES-BCT would amount to over 8 cents per kilowatt-hour—at least 60% higher. (At least 35 megawatts is still available for subscription.) This benefit amounts to over $1.2 million per year at current PG&E rates, compared to an expected annual lease payment under the current lease agreement ranging from $40,000 to $80,000. The gain in value over 50 years could be $52 million in nominal dollars or $21 million in net present value. That delivers an equivalent to a lease rate of $5,000 per acre, not $340 or less.

Even if the City did not use the power output, it should have negotiated a lease price based on either (1) the value of rezoned commercial and industrial land since the developer would have to get that zoning designation to develop its project elsewhere, or (2) the highest agricultural value (not the average for the county). For agricultural land, the value a City commissioner and orchard farmer has calculated is $1,688 to $2,250 per acre, or four to five times higher than the rate that the City negotiated based on a naïve calculation.

Further, the term sheet specifies that the developer pay the property taxes. However, the value of the parcels will not increase if the project is built prior to the 2025 because of the solar property exclusion in state law. The County will receive a short term boost in sales tax revenues from plant construction, but the City will not receive any share of that since its outside City boundaries. The City could have negotiated an in-lieu payment from the developer based on the added property value.

While the lease agreement pays lip service to the developer’s responsibility for decommissioning and disposing of the project at the end of its useful life, the term sheet has no provision prohibiting the developer from declaring bankruptcy for its limited liability corporation (LLC) and just walking away. Since the project will have no income at the end its life, and the entity owning the plant is legally separate from primary development firm (or its successor), the obvious step is to simply dissolve the LLC through a bankruptcy.  Such a step would leave the plant for the City to dispose of at significant expense (likely more than $1 million at today’s prices.)  This will wipe out half of the current lease revenues. That is the route that PG&E Corporation took in 2001 when its subsidiary, Pacific Gas and Electric Company, declared bankruptcy in 2001, leaving the bill of the energy crisis to ratepayers instead of shareholders. The City failed to require a surety bond that would cover those costs. Such bonds or other endowments are typical for projects of this type.

An additional consideration that appears to have been ignored is that The City has been looking at other higher value uses of the site such as organics waste disposal or habitat preservation and restoration. These have been under study at several City Commissions, but now those efforts have been aborted.

Finally, some of have defended maintaining the agreement because abrogating it could expose the City to significant legal liability. The developer at this time cannot sue for more than its demonstrated losses, and since it does not yet have a power purchase agreement, it has no future income stream to point to. At most, the liability is the $150,000 deposit with the CAISO  plus a few thousand dollars expended preparing and submitting the interconnection application (which in fact can be remediated with a $250,000 refundable deposit).

The agreement still faces several hurdles including whether the process violated California’s Brown Act, approval with any Yolo County zoning changes, conformance between the agreement and CAISO interconnection requirements, and winning with an RFO bid.

Even if the City believes that it is compelled to go forward with this agreement, it should admit that it made a series of serious mistakes and needs to review its practices and processes that caused this mess. Unfortunately, it does not seem that the City could have done any worse in these negotiations.

Richard McCann testified at the California Public Utilities Commission on behalf of Santa Clara and San Joaquin counties about their RES-BCT projects, and analyzed solar net metering arrangements for agricultural and mobilehome park clients. He evaluated the fiscal impacts of solar projects on San Luis Obispo, San Benito and Inyo counties, and projected the costs of the Desert Renewable Energy Conservation Plan for the California Energy Commission. He is a member of the Natural Resources Commission, former member of the Utilities Commission, and was recently recognized with  the City’s 2020 Environmental Recognition Award for serving on the Technical Advisory Subcommittee of the Community Choice Energy Advisory Committee, leading to formation of Valley Clean Energy.

Not grasping the concept: PG&E misses the peak load shift

Utility peak shifted by solar graph

PG&E in its 2020 ERRA Forecast Proceeding testimony wrote “however, BTM DG [behind the meter distributed generation] has a limited impact to the annual system peak as customer-owned solar photovoltaic (PV) generation is minimal during the peak hour of 7 p.m.” Uh, how does PG&E know that customer-owned solar doesn’t contribute to reducing the system peak if PG&E does not meter that generation?

PG&E actually has it wrong. Customer-owned solar has in fact reduced the former pre-solar peak that used to occur between 2 and 4 p.m. The metered load that PG&E can see, which is customer usage minus solar output (BTM DG), has shifted its apparent peak from 4 p.m. to 7 p.m.–3 hours. The graphic above illustrates how this shift has occurred. (PG&E produced a similar chart of its 2016 loads in its TOU rate rulemaking.) So BTM DG has had a profound impact on the annual system peak.

Lomborg has it wrong about California’s cap and trade program. 

Bjorn Lomborg, a Danish political scientist who has pushed for focusing spending on other pressing world needs over reducing climate change risk, has criticized the extension of California’s cap and trade program in the LA Times. I found two serious flaws in Lomborg’s analysis that undermine his conclusions.

The study that Lomberg cites about the electricity market impacts has not been reproduced since such extensive “contract reshuffling” can’t occur in the Western Electricity Coordinating Council (WECC) region or in the CAISO market. That’s just a simplistic modeling exercise not tied to reality. The fact is that thousands of megawatts of coal plants are retiring across the WECC at least in part in response to the cap & trade and renewables portfolio standards (RPS) adopted by California.

And then Lomberg writes “A smarter approach to climate policy — and one befitting California’s role as one of the most innovative states in the country — would be to focus on making green energy cheaper. ” Has Lomberg noticed that new solar and wind installations are now cheaper than new fossil-fueled plants? Contracts are being signed for less than 5 cents per kilowatt-hour–PG&E’s average cost for existing generation is close to 9 cents.

It’s as though Lomberg hasn’t updated his understanding of the energy industry since 2009 when the Copenhagen climate accord was signed.

Fighting the last war: Study finds solar + storage uneconomic now  | from Utility Dive

“A Rochester Institute of Technology study says a customer must face high electricity bills and unfavorable net metering or feed-in policies for grid defection to work.”

Yet…this study used current battery costs (at $350/KW-Hr), ignoring probably cost decreases, and then made more restrictive assumptions about how such a system might work. It’s not clear if “defection” meant complete self sufficiency, or reducing the generation portion (which in California about half of electricity bill.) Regardless, the study shows that grid defection is cost-effective in Hawaii, confirm the RMI findings. Even so, RMI said it would take at least 10 years before such defection was cost-effective in even the high-cost states like New York and California.

A more interesting study would be to look at the “break-even” cost thresholds for solar panels and batteries to make these competitive with utility service. Then planners and decision makers could assess the likelihood of reaching those levels within a range of time periods.

Source: A study throws cold water on residential solar-plus-storage economics | Utility Dive