Authors Ahmad Faruqui, Richard McCann and Fereidoon Sioshansi respond to Professor Severin Borenstein’s much-debated proposal to reform California’s net energy metering, which was first published as a blog and later in a Los Angeles Times op-ed.
Tag Archives: Energy Institute at Haas
Why utility prices cannot be set using short-run marginal costs
One commentator on the Energy Institute at Haas’ blog entitled “Everyone Should Pay a ‘Solar Tax’” points out that one version of economic theory holds that short run marginal cost is the appropriate metric for composing efficient prices. And he points out that short-run (SRMC) and long-run marginal costs (LRMC) should converge in equilibrium. So he implicitly says that long run marginal costs are the appropriate metric if as a stable long-run measure is based, as he states, on forecasts.
Even so, he misses an important aspect–using the SRMC for pricing relies on important conditions such as (1) relatively free entry and exit, (2) producers bear full risk for their investments, and (3) no requirements exist for minimum supply (i.e., no reserve margins). He points out that utilities overbuild their transmission and distribution (and I’ll point out their generation) systems. I would assert that is because of the market failures related to the fact that the conditions I listed above are missing–entry is restricted or prohibited, customers bear almost all of the risk, and reserve margins largely eliminates any potential for scarcity rents. In fact, California explicitly chose its reserve margin and resource adequacy procurement standards to eliminate the potential for pricing in the scarcity rents necessary for SRMC and LRMC to converge.
He correctly points out that apparent short run MC are quite low (not quite as close to zero as he asserts though)–a statement that implies that he expects that SRMC in a correctly functioning market would be much higher. In fact, as he states, the SRMC should converge to the LRMC. The fact is that SRMC has not risen to the LRMC on an annual average basis in decades in California (briefly in 2006, 2001 and 2000 (when generators exerted market power) and then back to the early 1980s). So why continue to insist that we should be using the current, incorrect SRMC as the benchmark when we know that it is wrong and we specifically know why its wrong? That we have these market failures to maintain system reliability and address the problems of network and monopolistic externalities is why we have regulation.
The solution is not to try to throw out our current regulatory scheme and then let the market price run free in the current institutional structure with a single dominant player. Avoiding market dominance is the raison d’etre for economic regulation. If that is the goal, the necessary first step is introducing and sustaining enough new entrants to be able to discipline the behavior of the dominant firm. Pricing reform must follow that change, not precede it. Competitive firms will not just spontaneously appear due to pricing reform.
It’s not clear that utilities “must” recover their “fixed” investments costs. Another of the needed fixes to the current regulatory scheme to improve efficiency is having utilities bear the risks of making incorrect investment decisions. Having warned (correctly) the IOUs about overforecasting demand growth for more than a dozen years now, they will not listen such analyses unless they have a financial incentive to do so.
Contrary to claims by this and other commentators, It is not efficient to charge customers a fixed charge beyond the service connection cost (which is about $10/month for residential customers for California IOUs). If the utility charges a fixed cost for the some portion of the rest of the grid, the efficient solution must then allow customers to sell their share of that grid to other customers to achieve Pareto optimal allocations among the customers. We could set up a cumbersome, high transaction cost auction or bulletin board to facilitate these trades, but there is at least another market mechanism that is nearly as efficient with much lower transaction costs–the dealer. (The NYSE uses a dealer market structure with market makers acting as dealers.) In the case of the utility grid, the utility that operates the grid also can act as the dealer. The most likely transaction unit would bein kilowatt-hours. So we’re left back where we started with volumetric rates. The problem with this model is not that it isn’t providing sufficient revenue certainty–that’s not an efficiency criterion. The problem is that the producer isn’t bearing enough of the risk of insufficient revenue recovery.
An alternative solution may be to set the distribution volumetric rate at the LRMC with no assurance of revenue requirement on that portion, and then recover the difference between average cost and LRMC in a fixed charge. This is the classic “lump sum” solution to setting monopoly pricing. The issue has been how to allocate those lump sum payments. However, the true distribution LRMC appears to be higher than average costs now based on how average rates have been rising.
What is the real threat to electrification? Not solar rooftops
The real threat to electrification are the rapidly escalating costs in the distribution system, not some anomaly in rate design related to net energy metering. As I have written here several times, rooftop solar if anything has saved ratepayers money so far, just as energy efficiency has done so. PG&E’s 2023 GRC is asking for a 66% increase in distribution rates by 2026 and average rates will approach 40 cents/kWh. We need to be asking why are these increases happening and what can we do to make electricity affordable for everyone.
Perhaps most importantly, the premise that there’s a “least cost” choice put forward by economists at the Energy Institute at Haas among others implies that there’s some centralized social welfare function. This is a mythological construct created for the convenience of economists (of which I’m one) to point to an “efficient” solution. Other societal objectives beyond economic efficiency include equitably allocating cost responsibility based on economic means, managing and sharing risks under uncertainty, and limiting political power that comes from economic assets. Efficiency itself is limited in what it tells us due to the multitude of market imperfections. The “theory of the second best” states that in an economic sector with uncorrected market failures, actions to correct market failures in another related sector with the intent of increasing economic efficiency may actually decrease overall economic efficiency. In the utility world for example, shareholders are protected from financial losses so revenue shortfalls are allocated to customers even as their demands fall. This blunts the risk incentive that is central to economic efficiency. Claiming that adding a fixed charge will “improve” efficiency has little basis without a complete, fundamental assessment of the sector’s market functionality.
The real actors here are individual customers who are making individual decisions in our current economic resource allocation system, and not a central entity dictating choices to each of us. Different customers have different preferences in what they value and what they fear. Rooftop installations have been driven to a large extent by a dread of utility mismanagement that makes expectations about future rates much more uncertain.
The single most important trait of a market economy is the discipline imposed by appropriately assigning risk burden to the decision make and not pricing design. The latter is the tail wagging the dog. Market distortions are universally caused by separating consequences from decisions. And right now the only ability customers have to exercise control over their electricity bills is to somehow exit the system. If we take away that means of discipline we will never be able to control electricity rates in a way that will lead to effective electrification.
A misguided perspective on California’s rooftop solar policy
Severin Borenstein at the Energy Institute at Haas has taken another shot at solar rooftop net energy metering (NEM). He has been a continual critic of California’s energy decentralization policies such as those on distribution energy resources (DER) and community choice aggregators (CCAs). And his viewpoints have been influential at the California Public Utilities Commission.
I read these two statements in his blog post and come to a very different conclusions:
“(I)ndividuals and businesses make investments in response to those policies, and many come to believe that they have a right to see those policies continue indefinitely.”
Yes, the investor owned utilities and certain large scale renewable firms have come to believe that they have a right to see their subsidies continue indefinitely. California utilities are receiving subsidies amounting to $5 billion a year due to poor generation portfolio management. You can see this in your bill with the PCIA. This dwarfs the purported subsidy from rooftop solar. Why no call for reforming how we recover these costs from ratepayers and force shareholder to carry their burden? (And I’m not even bringing up the other big source of rate increases in excessive transmission and distribution investment.)
Why wasn’t there a similar cry against bailing out PG&E in not one but TWO bankruptcies? Both PG&E and SCE have clearly relied on the belief that they deserve subsidies to continue staying in business. (SCE has ridden along behind PG&E in both cases to gain the spoils.) The focus needs to be on ALL players here if these types of subsidies are to be called out.
“(T)he reactions have largely been about how much subsidy rooftop solar companies in California need in order to stay in business.”
We are monitoring two very different sets of media then. I see much more about the ability of consumers to maintain an ability to gain a modicum of energy independence from large monopolies that compel that those consumers buy their service with no viable escape. I also see a reactions about how this will undermine directly our ability to reduce GHG emissions. This directly conflicts with the CEC’s Title 24 building standards that use rooftop solar to achieve net zero energy and electrification in new homes.
Along with the effort to kill CCAs, the apparent proposed solution is to concentrate all power procurement into the hands of three large utilities who haven’t demonstrated a particularly adroit ability at managing their portfolios. Why should we put all of our eggs into one (or three) baskets?
Borenstein continues to rely on an incorrect construct for cost savings created by rooftop solar that relies on short-run hourly wholesale market prices instead of the long-term costs of constructing new power plants, transmission rates derived from average embedded costs instead of full incremental costs and an assumption that distribution investment is not avoided by DER contrary to the methods used in the utilities’ own rate filings. He also appears to ignore the benefits of co-locating generation and storage locally–a set up that becomes much less financially viable if a customer adds storage but is still connected to the grid.
Yes, there are problems with the current compensation model for NEM customers, but we also need to recognize our commitments to customers who made investments believing they were doing the right thing. We need to acknowledge the savings that they created for all of us and the push they gave to lower technology costs. We need to recognize the full set of values that these customers provide and how the current electric market structure is too broken to properly compensate what we want customers to do next–to add more storage. Yet, the real first step is to start at the source of the problem–out of control utility costs that ratepayers are forced to bear entirely.
Part 2: A response to “Is Rooftop Solar Just Like Energy Efficiency?”
Severin Borenstein at the Energy Institute at Haas has written another blog post asserting that solar rooftop rates are inefficient and must changed radically. (I previously responded to an earlier post.) When looking at the efficiency of NEM rates, we need to look carefully at several elements of electricity market and the overall efficiency of utility ratemaking. We can see that we can come to a very different conclusion.
I filed testimony in the NEM 3.0 rulemaking last month where I calculated the incremental cost of transmission investment for new generation and the reduction in the CAISO peak load that looks to be attributable to solar rooftop.
- Using FERC Form 1 and CEC powerplant data, I calculated that the incremental cost of transmission is $37/MWH. (And this is conservative due to a couple of assumptions I made.) Interestingly, I had done a similar calculation for AEP in the PJM interconnect and also came up with $37/MWH. This seems to be a robust value in the right neighborhood.
- Load growth in California took a distinct change in trend in 2006 just as solar rooftop installations gained momentum. I found a 0.93 correlation between this change in trend and the amount of rooftop capacity installed. Using a simple trend, I calculated that the CAISO load decreased 6,000 MW with installation of 9,000 MW of rooftop solar. Looking at the 2005 CEC IEPR forecast, the peak reduction could be as large as 11,000 MW. CAISO also estimated in 2018 that rooftop solar displaced in $2.6 billion in transmission investment.
When we look at the utilities’ cost to acquire renewables and add in the cost of transmission, we see that the claim that grid-scale solar is so much cheaper than residential rooftop isn’t valid. The “green” market price benchmark used to set the PCIA shows that the average new RPS contract price in 2016 was still $92/MWH in 2016 and $74/MWH in 2017. These prices generally were for 30 year contracts, so the appropriate metric for comparing a NEM investment is against the vintage of RPS contracts signed in the year the rooftop project was installed. For 2016, adding in the transmission cost of $37/MWH, the comparable value is $129/MWH and in 2017, $111/MWH. In 2016, the average retail rates were $149/MWH for SCE, $183/MWH for PG&E and $205/MWH for SDG&E. (Note that PG&E’s rate had jumped $20/MWH in 2 years, while SCE’s had fallen $20/MWH.) In a “rough justice” way, the value of the displaced energy via rooftop solar was comparable to the retail rates which reflect the value of power to a customer, at least for NEM 1.0 and 2.0 customers. Rooftop solar was not “multiples” of grid scale solar.
These customers also took on investment risk. I calculated the payback period for a couple of customers around 2016 and found that a positive payback was dependent on utility rates rising at least 3% a year. This was not a foregone conclusion at the time because retail rates had actually be falling up to 2013 and new RPS contract prices were falling as well. No one was proposing to guarantee that these customers recover their investments if they made a mistake. That they are now instead benefiting is unwarranted hubris that ignores the flip side of the importance of investment risk–that investors who make a good efficient decision should reap the benefits. (We can discuss whether the magnitude of those benefits are fully warranted, but that’s a different one about distribution of income and wealth, not efficiency.)
Claiming that grid costs are fixed immutable amount simply isn’t a valid claim. SCE has been trying unsuccessfully to enact a “grid charge” with this claim since at least 2006. The intervening parties have successfully shown that grid costs in fact are responsive to reductions in demand. In addition, moving to a grid charge that creates a “ratchet effect” in revenue requirements where once a utility puts infrastructure in place, it faces no risk for poor investment decisions. On the other hand the utility can place its costs into ratebase and raise rates, which then raises the ratchet level on the fixed charge. One of the most important elements of a market economy that leads to efficient investment is that investors face the risk of not earning a return on an investment. That forces them to make prudent decisions. A “ratcheted” grid charge removes this risk even further for utilities. If we’re claiming that we are creating an “efficient” pricing policy, then we need to consider all sides of the equation.
The point that 50% of rooftop solar generation is used to offset internal use is important–while it may not be exactly like energy efficiency, it does have the most critical element of energy efficiency. That there are additional requirements to implement this is of second order importance, Otherwise we would think of demand response that uses dispatch controls as similarly distinct from EE. Those programs also require additional equipment and different rates. But in fact we sum those energy savings with LED bulbs and refrigerators.
An important element of the remaining 50% that is exported is that almost all of it is absorbed by neighboring houses and businesses on the same local circuit. Little of the power goes past the transformer at the top of the circuit. The primary voltage and transmission systems are largely unused. The excess capacity that remains on the system is now available for other customers to use. Whether investors should be able to recover their investment at the same annual rate in the face of excess capacity is an important question–in a competitive industry, the effective recovery rate would slow.
Finally, public purpose program (PPP) and wildfire mitigation costs are special cases that can be simply rolled up with other utility costs.
- The majority of PPP charges are a form of a tax intended for income redistribution. That function is admirable, but it shows the standard problem of relying on a form of a sales tax to finance such programs. A sales tax discourages purchases which then reduces the revenues available for income transfers, which then forces an increase in the sales tax. It’s time to stop financing the CARE and FERA programs from utility rates.
- Wildfire costs are created by a very specific subclass of customers who live in certain rural and wildlands-urban interface (WUI) areas. Those customers already received largely subsidized line extensions to install service and now we are unwilling to charge them the full cost of protecting their buildings. Once the state made the decision to socialize those costs instead, the costs became the responsibility of everyone, not just electricity customers. That means that these costs should be financed through taxes, not rates.
Again, if we are trying to make efficient policy, we need to look at the whole. It is is inefficient to finance these public costs through rates and it is incorrect to assert that there is an inefficient subsidy created if a set of customers are avoiding paying these rate components.
Part 1: A response to “Rooftop Solar Inequity”
Severin Borenstein at the Energy Institure at Haas has plunged into the politics of devising policies for rooftop solar systems. I respond to two of his blog posts in two parts here, with Part 1 today. I’ll start by posting a link to my earlier blog post that addresses many of the assertions here in detail. And I respond to to several other additional issues here.
First, the claims of rooftop solar subsidies has two fallacious premises. First, it double counts the stranded cost charge from poor portfolio procurement and management I reference above and discussed at greater length in my blog post. Take out that cost and the “subsidy” falls substantially. The second is that solar hasn’t displaced load growth. In reality utility loads and peak demand have been flat since 2006 and even declining over the last three years. Even the peak last August was 3,000 MW below the record in 2017 which in turn was only a few hundred MW above the 2006 peak. Rooftop solar has been a significant contributor to this decline. Displaced load means displaced distribution investment and gas fired generation (even though the IOUs have justified several billion in added investment by forecasted “growth” that didn’t materialized.) I have documented those phantom load growth forecasts in testimony at the CPUC since 2009. The cost of service studies supposedly showing these subsidies assume a static world in which nothing has changed with the introduction of rooftop solar. Of course nothing could be further from the truth.
Second TURN and Cal Advocates have all be pushing against decentralization of the grid for decades back to restructuring. Decentralization means that the forums at the CPUC become less important and their influence declines. They have all fought against CCAs for the same reason. They’ve been fighting solar rooftops almost since its inception as well. Yet they have failed to push for the incentives enacted in AB57 for the IOUs to manage their portfolios or to control the exorbitant contract terms and overabundance of early renewable contracts signed by the IOUs that is the primary reason for the exorbitant growth in rates.
Finally, there are many self citations to studies and others with the claim that the authors have no financial interest. E3 has significant financial interests in studies paid for by utilities, including the California IOUs. While they do many good studies, they also have produced studies with certain key shadings of assumptions that support IOUs’ positions. As for studies from the CPUC, commissioners frequently direct the expected outcome of these. The results from the Customer Choice Green Book in 2018 is a case in point. The CPUC knows where it’s political interests are and acts to satisfy those interests. (I have personally witnessed this first hand while being in the room.) Unfortunately many of the academic studies I see on these cost allocation issues don’t accurately reflect the various financial and regulatory arrangements and have misleading or incorrect findings. This happens simply because academics aren’t involved in the “dirty” process of ratemaking and can’t know these things from a distance. (The best academic studies are those done by those who worked in the bowels of those agencies and then went to academics.)
We are at a point where we can start seeing the additional benefits of decentralized energy resources. The most important may be the resilience to be gained by integrating DERs with EVs to ride out local distribution outages (which are 15 times more likely to occur than generation and transmission outages) once the utilities agree to enable this technology that already exists. Another may be the erosion of the political power wielded by large centralized corporate interests. (There was a recent paper showing how increasing market concentration has led to large wealth transfers to corporate shareholders since 1980.) And this debate has highlighted the elephant in the room–how utility shareholders have escaped cost responsibility for decades which has led to our expensive, wasteful system. We need to be asking this fundamental question–where is the shareholders’ skin in this game? “Obligation to serve” isn’t a blank check.
What is driving California’s high electricity prices?
This report by Next10 and the University of California Energy Institute was prepared for the CPUC’s en banc hearing February 24. The report compares average electricity rates against other states, and against an estimate of “marginal costs”. (The latter estimate is too low but appears to rely mostly on the E3 Avoided Cost Calculator.) It shows those rates to be multiples of the marginal costs. (PG&E’s General Rate Case workpapers calculates that its rates are about double the marginal costs estimated in that proceeding.) The study attempts to list the reasons why the authors think these rates are too high, but it misses the real drivers on these rate increases. It also uses an incorrect method for calculating the market value of acquisitions and deferred investments, using the current market value instead of the value at the time that the decisions were made.
We can explore the reasons why PG&E’s rates are so high, much of which is applicable to the other two utilities as well. Starting with generation costs, PG&E’s portfolio mismanagement is not explained away with a simple assertion that the utility bought when prices were higher. In fact, PG&E failed in several ways.
First, PG&E knew about the risk of customer exit as early as 2010 as revealed during the PCIA rulemaking hearings in 2018. PG&E continued to procure as though it would be serving its entire service area instead of planning for the rise of CCAs. Further PG&E also was told as early as 2010 (in my GRC testimony) that it was consistently forecasting too high, but it didn’t bother to correct thee error. Instead, service area load is basically at the save level that it was a decade ago.
Second, PG&E could have procured in stages rather than in two large rounds of request for offers (RFOs) which it finished by 2013. By 2011 PG&E should have realized that solar costs were dropping quickly (if they had read the CEC Cost of Generation Report that I managed) and that it should have rolled out the RFOs in a manner to take advantage of that improvement. Further, they could have signed PPAs for the minimum period under state law of 10 years rather than the industry standard 30 years. PG&E was managing its portfolio in the standard practice manner which was foolish in the face of what was occurring.
Third, PG&E failed to offer part of its portfolio for sale to CCAs as they departed until 2018. Instead, PG&E could have unloaded its expensive portfolio in stages starting in 2010. The ease of the recent RPS sales illustrates that PG&E’s claims about creditworthiness and other problems had no foundation.
I calculated the what the cost of PG&E’s mismanagement has been here. While SCE and SDG&E have not faced the same degree of exit by CCAs, the same basic problems exist in their portfolios.
Another factor for PG&E is the fact that ratepayers have paid twice for Diablo Canyon. I explain here how PG&E fully recovered its initial investment costs by 1998, but as part of restructuring got to roll most of its costs back into rates. Fortunately these units retire by 2025 and rates will go down substantially as a result.
In distribution costs, both PG&E and SCE requested over $2 billion for “new growth” in each of its GRCs since 2009, despite my testimony showing that growth was not going to materialize, and did not materialize. If the growth was arising from the addition of new developments, the developers and new customers should have been paying for those additions through the line extension rules that assign that cost responsibility. The utilities’ distribution planning process is opaque. When asked for the workpapers underlying the planning process, both PG&E and SCE responded that the entirety were contained in the Word tables in each of their testimonies. The growth projections had not been reconciled with the system load forecasts until this latest GRC, so the totals of the individual planning units exceeded the projected total system growth (which was too high as well when compared to both other internal growth projections and realized growth). The result is a gross overinvestment in distribution infrastructure with substantial overcapacity in many places.
For transmission, the true incremental cost has not been fully reported which means that other cost-effective solutions, including smaller and closer renewables, have been ignored. Transmission rates have more than doubled over the last decade as a result.
The Next10 report does not appear to reflect the full value of public purpose program spending on energy efficiency, in large part because it uses a short-run estimate of marginal costs. The report similarly underestimates the value of behind-the-meter solar rooftops as well. The correct method for both is to use the market value of deferred resources–generation, transmission and distribution–when those resources were added. So for example, a solar rooftop installed in 2013 was displacing utility scale renewables that cost more than $100 per megawatt-hour. These should not be compared to the current market value of less than $60 per megawatt-hour because that investment was not made on a speculative basis–it was a contract based on embedded utility costs.
Drawing too many conclusions about electric vehicles from an obsolete data set
The Energy Institute at Haas at the University of California published a study allegedly showing that electric vehicles are driven about only one-third of the average standard car in California. I responded with a response on the blog.
Catherine Wolfram writes, “But, we do not see any detectable changes in our results from 2014 to 2017, and some of the same factors were at play over this time period. This makes us think that newer data might not be dramatically different, but we don’t know.“
A recent study likely is delivering a biased estimate of future EV use. The timing of this study reminds me of trying to analyze cell phone use in the mid-2000s. Now household land lines are largely obsolete, and we use phones even more than we did then. The period used for the analysis was during a dramatically changing period more akin to solar panel evolution just before and after 2010, before panels were ubiquitous. We can see this evolution here for example. Comparing the Nissan Leaf, we can see that the range has increased 50% between the 2018 and 2021 models.
The primary reason why this data set is seeing such low mileage is because is almost certain that the vast majority of the households in the survey also have a standard ICE vehicle that they use for their extended trips. There were few or no remote fast charge stations during that time and even Tesla’s had limited range in comparison. In addition, it’s almost certain that EV households were concentrated in urban households that have a comparatively low VMT. (Otherwise, why do studies show that these same neighborhoods have low GHG emissions on average?) Only about one-third of VMT is associated with commuting, another third with errands and tasks and a third with travel. There were few if any SUV EVs that would be more likely to be used for errands, and EVs have been smaller vehicles until recently.
As for copurchased solar panel installation, these earlier studies found that 40% or more of EV owners have solar panels, and solar rooftop penetration has grown faster than EV adoption since these were done.
I’m also not sure that the paper has captured fully workplace and parking structure charging. The logistical challenges of gaining LCFS credits could be substantial enough for employers and municipalities to not bother. This assumption requires a closer analysis of which entities are actually claiming these credits.
A necessary refinement is to compare this data to the typical VMT for these types of households, and to compare the mileage for model types. Smaller commuter models average less annual VMT according to the California Energy Commission’s vehicle VMT data set derived from the DMV registration file and the Air Resources Board’s EMFAC model. The Energy Institute analysis arrives at the same findings that EV studies in the mid 1990s found with less robust technology. That should be a flag that something is amiss in the results.
Reaction to Is “Community Choice” Electric Supply a Solution or a Problem?
Severin Borenstein at the Energy Institute @ Haas wrote a good summary of the issues around community choice aggregation.
Source: Is “Community Choice” Electric Supply a Solution or a Problem?
I am on the City of Davis’ Community Choice Energy Advisory Committee and have been looking at these issues closely for a year. I had my own reactions to this post:
First, in California the existing and proposed CCEs (there are probably a dozen in process at the moment to add to the 3 existing ones) universally offer a higher “green” % product than the incumbent IOU, most often a 50% RPS product. And although MCE and SCP started out relying on RECs of various types to start out, they all are phasing out most of those by 2017. I think most will offer a 100% product as well.
The reason that these CCE’s are able to offer lower rates than the IOUs at a lower RPS is that the IOUs prematurely contracted long for renewables in anticipation of the 2020 goal. In fact, the penalty for failing to meet the RPS in any given year is so low, that the prudent strategy by an IOU would have been to risk being short in each year and contract for the year ahead instead of locking in too many 20+ year PPAs. At least one reason why this happened is that the IOUs require confidentiality by any reviewers and no connections to any competing procurement decisions. As a result the outside reviewers couldn’t be up to speed on the rapidly falling PPA prices. The CPUC has made a huge mistake on this point (and the CEC has rightfully harassed the CPUC over this policy.)
CCE’s also offer the ability to craft a broader range of rate offerings to customers–even flat 20 year rates that can compete with solar roofs on the main issue that customers really care about: price guarantees. In addition, CCE’s are more likely to be to nimbly adjust a rapidly changing utility landscape. CCE’s are much less likely to care about falling loads because their earnings aren’t dependent on continued service.
It’s also to recognize the difference between local government general services (e.g., safety and public protection, social services, regulation, etc.) and enterprise services (e.g., utilities of all sorts). In general, the latter are as efficient as IOUs (except LADWP which illustrates the INefficiency created by overlarge organizations). So one can’t make a broad generalization about local government problems and how they might apply in this situation. The fact is that almost all of the existing and new CCEs are or will be JPAs, which are often even leaner. (Lancaster is the exception.)
Finally, Severin made this statement:
“Whatever regulatory mandates, managerial mistakes, or incompetence occurred in the past, customers switching to a CCA should not be allowed to shift their share of costs from past decisions onto other ratepayers.”
I have to disagree to a certain exent with this statement. Am I forced to pay for the past incompetencies of GM or GE or any other corporation? Yes, utilities have a higher assurance of return on their investments, but no where is it written that it is “ironclad.” Those utilities had an assurance first as the sole legal provider and then as the provider of last resort, but that’s eroding. In California, the CTC was a political deal to get the IOUs out of the way. The fact is in California that the CPUC abrogated its responsibility to oversee these decisions on behalf of ratepayers with the encouragement of the IOUs. If the IOUs want to retain their customers, then they should be forced to compete with the CCEs (and DA LSEs.) It’s time to reopen this matter.
And to add a bit more:
The logic of this statement is that ANY customer who leaves the system, including moving to another area, state or nation, should have to continue to pay these stranded costs. Why should we draw the line arbitrarily at whether they happen to still get distribution services even though the generation services have been completely severed? Particularly if someone moves from say, San Francisco to Palo Alto, that customer still relies on PG&E’s transmission system and its hydro system for ancillary services. Why not charge that Palo Alto customer a non-by-passable charge? And why shouldn’t it be reciprocal? Relying on “political practicality” is not an answer. Either ALL customers are tethered forever, or no customers are required to meet this obligation.
A brief reply to “Real” Electricity Still Comes from the Grid
Source: “Real” Electricity Still Comes from the Grid
Catherine Wolfram at UC Berkeley posted about their paper looking at costs of distributed energy systems in Kenya and concluding that these were too expensive for households compared to connecting to the grid. However, the paper came under immediate criticism.
Here’s my thoughts based on her representation of the paper’s findings, some of which are mirrored by other commentators:
First, the paper talks about costs on one side, but doesn’t put them in perspective to the alternatives. The post lists the cost of the individual systems, but not the expected connection costs to the grid.
Further the paper takes a static look at current costs and doesn’t account for the differential trends in the sets of costs for an home-based system versus connecting to the grid. The latter costs can be expected to be steady or even rising, while it’s well known that both solar and storage costs have fallen rapidly.
Different scales of “grid” also are important. For example, solar projects show scale economies up to about 3 MW but then modular construction flattens the per kW cost. A village microgrid separate from a national central grid may be quite cost competitive.
Finally, the paper appears to lump large hydro in with other utility-scale renewables. The environmental (and economic development) record for large-scale hydro projects in the developing world is dubious at best. There is evidence of significant methane emissions from tropical reservoirs. Habitat is destroyed and poorly designed projects don’t deliver expected benefits. Hydro is by far the largest energy supplier on these grids, and they may be little better than coal from an overall environmental perspective.