Moving On…

After two years providing analysis, direction, and assistance to companies across the distributed energy space, I have decided to take on a new role – Deputy Director of Sustainability at the City of San Diego.  While I will miss the opportunity (and flexibility) of working with a broad variety of companies in all different stages and areas of the industry, I cannot wait to get started on the broad portfolio of project the city is taking on.

The good news is, as a public servant, I am still around to answer questions and provide feedback as to what is happening in the industry, so feel free to reach out – especially if you are based here in San Diego or California more broadly.


Election Impact: Preparing for 2019

While we’re still waiting for the final vote tallies in 10 House districts across the country and gubernatorial and senate races in the southeast, I want to give a couple of quick insights and sign posts given the results of the midterms both at the federal level and in the states to start watching for new opportunities.

The immediate takeaway is that, with Trump still in office and determined to keep backing fossil fuels and undoing EPA rules, and Republicans in the Senate following his lead, no major clean energy legislation is going to pass over the next two years. However, with the Democrats controlling the House, they do have some significant leverage on a critical area of legislation: the power of the purse.

No matter what the purpose of the bill may be, any legislation that requires fiscal expenditures must be initiated by the House of Representatives. And that means government affairs and leadership teams need to start paying close attention to the people and schedules of the subcommittees of the House Appropriations Committee – specifically the subcommittees for Commerce, Justice, Science; Energy and Water Development; Interior and Environment; and Transportation, Housing and Urban Development. If you are looking to start educating and influencing the new House Democrats for policies they are developing, get to know the new members of the House Energy & Commerce Committee. And pay attention to who gets appointed to the renewed Select Committee on Climate Change that Leader Pelosi has committed to re-establishing come January.

But, as usual in energy policy, it’s the states where all the interesting things happen. While there are lots of interesting issues being dealt with in all the states (seriously, start paying attention to Kentucky, Indiana, and Tennessee for new solar growth), the big takeaway from last Tuesday is the eight gubernatorial candidates who ran and won on an 80-100% renewable energy platform. These are: Colorado, Connecticut, Illinois, Maine, Michigan, Nevada, New Mexico, and Oregon.

How each of these Governor-elects will approach this goal is going to be as diverse as their states, but increasing investment in EV infrastructure, clearing obstacles for more distributed energy (specifically rooftop solar), and appointing PUC/PSC commissioners focused on grid modernization are likely places to start. Steve Sisolak and his new Democratic trifecta could make the need for a second passage of the RPS increase ballot measure obsolete in Nevada by legislating it in his first 100 days. Jared Polis is focused on returning Colorado to its leadership position in renewable energy growth and his 100% RE victory takes a lot of wind out of the coal lobby’s sails. And if you are in the AI/tech space, keep a close on on Michigan – Gretchen Witmer is determined to make her state a central hub for autonomous vehicle development to draw more high tech jobs into the core automotive manufacturing sector it’s known for.

Former Vice President Joe Biden would use a common refrain when talking about policy and governance: “Show me you budget and I’ll show you your priorities.” Just as at the federal level, campaign platforms and policy statements are a good start, but it’s the state budgets that indicate real support and drive for change. As you start planning new market strategies, always follow the money.

Storage Roundup

A quick roundup of news on storage regulation at all levels of the market lately:



  • There are a rising number of storage capacity mandates coming out of states all over the country including NY, MA, and NJ.
  • In the meantime, incentive programs such as California’s Self-Generation Incentive Program (SGIP) was extended at the end of last month when Brown signed SB 700 into law.
  • In addition to SB 700, the completion of the time-of-use rollout for all customers in CA, the self-generation rate structures in Hawaii, and the upcoming NEM 3.0 rate case in CA along with several other successor tariff decisions throughout the Midwest will affect the economics of pure solar for customers that may be balanced out with on-site storage.
  • With an eye toward political timing, NV Energy just announced new solicitation for 350 MW of renewable energy paired with storage, but keep an eye on Question 3 which would mandate the deregulation of Nevada’s electricity market – and throw much of the utilities recent moves into limbo.
  • Keep an eye on Arizona! While the ballot initiative to require the state to get raise their RPS to 50% under Proposition 127, the interesting regulatory issue is the docket to review the Arizona Energy Modernization Plan (AEMP) with a strategy to get to 80% non-emitting (renewable + nuclear) by 2050 including a 3GW storage target for utilities.

CA Legislative Session 2018 (Cleantech San Diego presentation)

Last week, I was on a Cleantech San Diego panel covering some of the 30+ energy-related bills passed and signed in California this year.   I’ve decided to share my section of the slides here: CTSD Semper Varia Legislative Overview slides

In relation to the last bill I discuss, SB 1136 (Hertzberg), if you are interested in more detail regarding how Resource Adequacy (RA) requirements work and more background on this bill, check out Utility Dive’s article on removing natural gas from the CA electricity mix. 

There’s something happening here…

While still early days, I want to flag a few signals that renewable energy is making inroads in states and markets where it once seemed impossible. Renewable energy developers may want to keep an eye on states such as Kentucky, Alabama, Tennessee, and Mississippi.

In 2013, Duke Energy proposed a green energy rider to their standard commercial electricity rate in North Carolina.  The utility was responding to significant pressure from outside companies – namely tech companies like Apple and Google – to provide a significantly higher percentage of electricity from renewable energy than the state’s 12% RPS required.  With the addition of the rider, significant renewables development by technology companies on-site, and meeting the RPS, by 2015 North Carolina was one of the fastest growing solar states in the country.

This was not the first major utility in a state to request to add a green rider or green tariff to their rate book nor were they the last.  In each case, the request reflected significant customer pressure for a cleaner generation portfolio and served as a major market trigger for significant renewables growth in the following few years. The most recent request? Kentucky.

Though known as a coal state, it seems Kentucky utilities, businesses, and regulators are starting to see the cost savings and economic benefits of renewable power.  Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU) said recently that they will propose a Green Tariff to promote renewable energy growth and economic development in a rate review filing on Sept. 28.  As is often the case, it was actually the municipal utilities that led the charge. In early August, the KY Municipal Energy Authority signed an agreement for the development of a new 86 MW solar plant on 800 acres in the western Kentucky – 10 times larger than any other solar installation in the state thus far.

One other item to keep an eye on if you are watching Appalachia – a lawsuit filed against the Tennessee Valley Authority (TVA) in the northern district of Alabama.  The suit, brought by five environmental groups, claims a new TVA rate structure severely undermines the economics of distributed energy resources like rooftop solar and energy efficiency investments. The lawsuit itself is not particularly revolutionary, but the unique nature of the TVA makes its potential impact all the more interesting.  Because the TVA is a government agency with a board appointed by the President of the United States, it’s not subject to any state-level utilities commission (similar to SRP in Arizona).  It also means that any lawsuit that finds the rate structures unjust or discriminatory are applicable for the entire TVA territory – potentially opening up not just northern Alabama but also all of Tennessee and parts of Kentucky, Georgia, North Carolina, and Mississippi.

Managing Expectations on Value-Stacking

The discussion around “value-stacking” rates has been cropping up again in the distributed space – primarily in discussions around batteries and microgrids – along with frustration at the lack of movement toward such a structure. While value-stacking is a good paradigm and most electricity markets will get there, in some form eventually, I’ve found this frustration is rooted more in mismanaged expectations than some imagined backroom boogeyman.

What is “value-stacking”?

There are several technical capabilities necessary for a stable electrical grid to move power from the point of generation to the point of consumption.  These include frequency and voltage regulation, instant generation (“black start”) to cover gaps or failures, and spinning reserves. In most markets, ancillary services needs are provided by major generators (IPPs) bid into an ancillary services or capacity market mechanisms in parallel to their energy generation bids. To compete in these markets, a provider must meet a certain capacity criteria (usually at least 100kW) – too big for many distributed energy systems.

Battery Services to Multiple Points on the Grid

Credit: NREL

However, with multiple different types of technology affixed to the grid on the distribution end of the system – many of which can provide at least some if not all of these ancillary services at the point of need – there is an advancing argument that these services should be disaggregated and priced in some way for more technologies and providers to compete.  The NREL diagram to the right illustrates the multiple services batteries can provide at multiple levels of the grid.

The idea of value-stacking is to enable a single site with a single technology, or cluster of technologies acting as single entity, to provide some or all of these services  – receiving revenue for each type of service in the “stack.”  The challenges to implementing a value-stacking system are not insurmountable, but they are complicated and thus their solutions are complex and time-consuming.

Challenge 1: Multi-variable Algorithms and the Point of Diminishing Returns

This challenge assumes a market-based structure establishing the clearing price for each piece of value-stack.  This presents both technical and economic limiters to overcome.  Technically, if you want a competitive market system based on known needs in addition to instantaneous (spot) bid/response/pricing signals when unanticipated ancillary services are needed, you need a software platform that is running multi-variable algorithms in real time, and a circuit system that is adapting to the location of those services as they are provided.  This is technically possible, but it’s not technically present in current RTO/ISO platforms.

In addition to the software challenge, not all ancillary services are created equal.  The value proposition of a single service, like black start, may not be enough to cover the cost of production and deployment of a product that provides.  Hardware, or hardware clusters, would only reach a profitable threshold if they are able to provide multiple services per unit.   However, if a DER provider must have multiple services available to viably recover revenue, why disaggregate services at all?  The answer is time – a cluster of services will not all be needed at the same time at the same price on any given day/month/season.  This leaves system operators trying to determine the minimum cluster of services that must be available from any bidder to feel comfortable that the provider winning a bid for any one service is financially stable enough to still be around to provide it when it is needed.

It also leads to a challenging financing conversation for executives that goes something like “Our widget can provide multiple services to the grid at unknown prices for an unknown period of need through an unknown number of occurrences. Would you like to invest?”

Challenge 2: Market vs Rates

The solution to the first challenge, at least the economics and financing part of it (the technology answer is “consistently write and maintain new software”), is to set a specific price for each service. Forget the open market signals and just theoretically calculate the average value and set a rate.   Every time a participant provides the service, they get paid or credited at that rate – multiple services, multiple payments.  This solves the financing problem for service providers, negates the need for increasingly complex multi-variable algorithms in RTO/ISO platforms, and establishes the point of diminishing returns for investment into providing any one service. This is why most people talk about value-stacking rates – it’s like net metering for more than just generation.

So, what’s the challenge? That it’s like net metering for more than just generation.  While no economic policy is without politics, for the most part, market-based pricing signals based on demand requirements take a lot of the special interests out of day-to-day financial returns.  Establishing a rate, or multiple rates, opens the door of those interests to argue in favor of stakeholders’ priorities ranging from system stability to continued financial viability.  The fight over net metering in states across the country reflects how complicated, convoluted, and in some cases downright ugly, the fight over non-utility owned services can get in rate cases.

While a value-stacked rate structure is the most likely outcome in the long-term to provide the best solution at the lowest customer cost for ancillary services, the fight over that structure hasn’t really even begun. Simplifying the economic solution with set rates for various disaggregated services has the unfortunate consequence of complicating the technical management of the grid itself.

If services are being provided at the distribution level, does the utility determine the type of signal and to whom it is sent on the grid when ancillary services are necessary? How do they manage who “wins” for any particular need? What investments are needed to provide such signals?  How will they get audited? Who is responsible if the service isn’t provided and the grid destabilizes? Most importantly, will utilities be allowed to rate-base the cost of technical platforms and management systems to enable such services even though they aren’t infrastructure capital costs?

Not If, But When

I have yet to interact with any organization, as an employee, a consultant, or a customer, that doesn’t have at least one tale of “great idea, lousy execution.” In the electricity sector, lousy execution can have dire results – economically, technically, or sometimes both.  Regulatory bodies are risk averse, utilities are slow to change, and market models are shackled by inertia. This is not to say that the mechanism for distributed grid service providers will never manifest – keep an eye on Hawaii’s new performance-based revenue structures for early innovations.  But be realistic about the timing when thinking about expected revenue and growth, in any sales and savings pitch, or level of confidence that your side will win in the coming value-stack debates.

The stranded assets problem

If you wanted to point to a single year as the source of the current challenges facing the California electricity market and the major choices it’s leaders are confronting, it would be 2002.  This was the year of AB 117, the bill authorized community choice aggregation; the year of SB 1078 that established the original Renewable Portfolio Standard;  the first year the major generation capacity contracted in response to the 2000-01 electricity crisis came online; and the year the CPUC started allowing utilities to negotiate long-term PPA contracts with independent power producers (IPPs / generators).  No single one of these policies is the cause of the current turmoil but their convergence has given rise to a core problem in the changing California market: stranded assets.

The stranded asset problem is not new – it shows up in any basic investment risk assessment of any business.  Even in the California utility market, the stranded asset problem arose in the early 90s when the legislature and the Public Utility Commission (CPUC) were mapping out how to deregulate the electricity market – forcing the IOUs to sell all but a few of their physical generating assets. But unlike Finance 101 or mid-90s California, this time stranded assets are not physical (or technical) investments – they are contracts. Specifically, long-term Production Procurement Agreements (PPAs) with IPPs.

These contracts establish a set $/kwh price (plus additional prices for frequency and other ancillary services) and a minimum purchase amount by the utility annually for the life of the contract (usually 25-30 years).   These prices are then passed directly through to the customers on the “energy” line item of their bill.   In response to the RPS, several of these new contracts over the next 10 years were for renewable power – solar and wind – at prices that reflected the cost of these technologies before the significant drop in $/W in the early 2010s.  Hence the bid price of a solar plant into the CAISO wholesale market is exponentially lower now than the contracted price the utility (and thus customers) end up paying.   These contracts also assumed a load growth over that 25 year period that has, in reality, flatlined after the 2008 economic crash and doesn’t look like it’s coming back any time soon, if at all.

Many point to the rise of CCAs in California, starting in 2010, as reflective of the public belief that utilities are not moving fast enough to run the entire electric grid on 100% renewable energy.  However, while that is a strong local selling point, the state could reach that goal with the simple act of passing SB 100 and moving (and redefining) the RPS to 100% renewable. What makes the CCA case so strong is the economics – the opportunity to deliver cheaper power to communities because renewable power in California is significantly cheaper than what we’re paying for it.

The stranded asset problem, as it manifests in the CCA challenge, is embodied in the Power Charge Indifference Adjustment (PCIA).  The PCIA is intended to balance the contracted payments the IOU owes generators for the remaining life of a PPA for power customers are now buying from their CCA at lower rates.  It’s wrong to have customers staying with the IOU make up the difference in cost, and the utilities just not paying the bills would send them into bankruptcy (not a good idea).  The argument then – as seen in the current CPUC docket – is what and how should the PCIA be calculated.  Not surprisingly, CCAs argue that its current calculation is too high and the IOUs argue that it’s too low.  The Utility Dive article here gives a good overview of the changes each side is proposing.

But there is a larger structural challenge that this decision – depending on its result – will either inform or avoid.  The issue of stranded assets and the incentive structure of the cost-of-service utility revenue model.  Both Moody’s and the Rocky Mountain Institute have released reports in the last week pointing to the risks to major utilities in further investment in natural gas generation.  Not coal. Natural Gas.  What they both highlight is that with the increasing growth and decreasing price of renewable generation – utility-scale, corporate direct access contracts, and distributed energy resources – significant investment is more natural gas generation, utilities and energy companies are risking a serious stranded asset problem not just in California but across the country.

In 2002, California was already exerting significant political effort to transition the electric grid onto cleaner natural gas as a “bridging fuel” to renewable energy.  The general market and investment expectation was that that bridge would be necessary for about 30-40 years until renewables could really take over the majority of power production in the country.  It turns out renewables are running 15 years ahead of schedule and both the political and financial worlds have been caught off guard.  The stranded asset problem is rolling down the tracks and picking up speed.  It is imperative we come to a solution – one that will likely leave everyone a little pissed off but hopefully no one completely screwed over – before we get run over by the oncoming train.

You keep using that acronym…it may not mean what you think it means

There’s a vote today/tomorrow at the California Energy Commission (CEC) that has thrust “ZNE” back into the headlines. “ZNE” in this case stands for “Zero Net Energy” – the goal for a building to have onsite (or nearby) renewable generation and building efficiency investments such that it generates as much electricity as it consumes over the course of a month or a year.  But there is a new trend occurring in California policy language that is replacing “energy” with “emissions” in the ZNE calculation.  A shift that has major implications for the energy landscape.

While energy is a broad category, in policy, zero net energy is almost exclusively used in reference to electricity. This is best illustrated by the progression of building standards from the California Energy Commission from basic efficiency increases to upcoming ZNE requirements in new residential construction.  Yet even before these new standards go into effect in 2020, there is now a new bill (AB 3232) which directs the CEC to open a new proceeding to determine how to get energy use to zero emissions.

The primary source of this language adjustment can be traced to the three major utilities (IOUs).  As California policy makers and clean energy advocates pushed to decarbonize the grid, the IOUs started countering that the overarching goal should be a decrease of emissions and therefore policy should focus more on transportation – now responsible for a greater percentage of GHG emissions than electricity – instead of continuing the push toward a 100% renewable grid. A shift in focus to transportation could also drive incentive dollars toward greater EV deployment and lead to bills like AB 1745 that seeks to eliminate the sales of internal combustion engine cars and trucks by 2040. (Originally I’d qualify 1745 as a moonshot bill this session, but with Trump and Pruitt’s recent shot across the bow on emissions standards, movement on this bill may reveal just how ornery the CA legislature is feeling this election year).

While an increase in EVs may help the IOUs electricity business, success in changing the policy language and scope of from power to emissions may end up a pyrrhic victory. Advanced energy industries in the electricity sector lose nothing by changing measurements from clean generation to decreased or avoided emissions. The recent headlines from Portugal on what can best be described as a “zero net emissions” month on their electricity grid shows why. Broadening the focus to emissions will still incentivize new clean technologies but instead of moving the electricity sector out of frame, it could put a target on the other half of the IOUs business – natural gas.

If we clean up electricity and use it to power transportation, our remaining emissions are driven by the demand for heat.  Natural gas demand in the US is relatively evenly split between heat demand for building temperature and for industrial processes.  In the residential and commercial sector, electrifying heat demand is technically possible. However, as a recent GTM article illustrated, it’s not an easy, or economic, process – revealing a lot of low-hanging fruit in this space. Policies originally designed to drive fuel switching from dirty coal electricity to cleaner natural gas 20 years ago are now disincentivizing switching from GHG-producing gas back to a now 65-75% zero-emissions* grid. In a ZE policy environment, these will be first on the block.

This risk to utilities natural gas business was clearly seen recently in Sempra’s Very Bad Week™.  In addition to new natural gas plant denials in place of DER aggregation and storage, the CPUC looks like it will deny the SDG&E petition to build a new gas pipeline through San Diego, and SoCalGas was caught out working against efficiency programs that would drive down demand. Sempra’s recent 10-k filing specifically calls out the inherent risk of zero emissions policies to its shareholder returns.

The question remains on how quickly this transition from energy-ZNE to emissions-ZE will take. There are components of emissions-oriented measurements already in effect such as California’s cap and trade mechanism – another example of a “zero net emissions” approach – or 2015’s AB 802 requiring any >50,000 sqft building to submit energy and efficiency data to the CEC for benchmarking.  But the real political signal flare will be if and when a California governor stops talking about cleaning up specific market sectors and throws down the ZE gauntlet – publicly setting the long-term goal of a zero emissions economy.

*All renewables, hydro, and nuclear

Happy (Belated) Birthday to Us!

I just realized that Semper Varia turned a year old last week (April 17th to be precise)!  I’m really proud of the work and support this company has provided clients over the last year and look forward to new adventures in this ever-shifting market of ours. Thank you to everyone who supported and cheered me on over the last year.  Onward!

ITC Section 201 Decision

The next 24 hours are going to be filled with hot takes and calculations regarding the ITC announcement of tariffs on solar cells. I have three.

1) No, it’s not as bad as it could have been, but SEIA is projecting up to 23,000 solar jobs at risk in the US because of the tariffs. So it still sucks.
2) Anticipate increased logistics costs to cover warehousing as outside solar companies stay competitive by front-loading & warehousing 2.5GW cumulative each year and selling to spec when they’re gone.
3) Combined w/ the changes in the tax code, we’re likely going to see a shift in the timing of commissioning systems from Q4 to Q3 (maybe Q2) which are going to screw up companies’ QFY1/QFY2 numbers for a little while. Don’t panic.

You can read the decision here.