Tag Archives: energy management

Overwhelmed by “opportunities” at the CPUC

The opening of yet another rulemaking at the CPUC and the revelations of more contacts between PG&E and CPUC Commissioners are two sides of a larger conundrum in state electricity policy development and implementation. The OECD recently issued a wish list for how regulatory agencies should be structured and behave. (Thanks to Mark Pearson for posting this.) Yes, some are “pie in the sky” but they provide a useful means of evaluating how a regulatory agency is performing.

Looking at the first principle, the CPUC has been set adrift in part by the lack of role clarity in the state. At one point at least 8 statewide agencies had significant roles in electricity planning and ratemaking. (Along with the CPUC, there’s been the CEC, CAISO, CARB, CDWR, SWRCB, Electricity Oversight Board, and California Power Authority, the last 2 now defunct.) And there are additional local agencies (e.g., SCAQMD). This has blurred the lines of authority and allowed forum shopping.

And perhaps most importantly the number of proceedings at the CPUC have proliferated to a point where it is impossible for intervenors to devote enough resources to follow what’s happening everywhere. At least 14 different rulemakings are looking at interdependent elements of planning for increased renewables and the transformation of the electricity market. These include the long term power procurement, renewables portfolio standard, energy efficiency, water-energy nexus, demand side response, utility shareholder incentives, storage, distributed generation and self generationsolar initiative, net energy metering, alternative fueled and electric vehiclesresidential rate design, CCA rules, and recently, distribution resources planning.  And these don’t count the many utility applications such as the green tariff and community solar garden proposals. Some of these proceedings have been open over a decade with only partial resolution, and the CPUC has opened direct successors up to 4 times. While looking to develop a consistent regulatory framework for evaluating integrated demand side resources is an admirable goal, it could be overwhelmed by the divided attention demanded from all of these other proceedings. That undermines another OECD principle–transparency–even if appearances look differently.

Finally funding for both intervenors and skilled CPUC staff has become untenable and effective participation in declining, further eroding yet another OECD principle. This allows the well-funded utilities to influence outcomes while no one is looking. The documentation of the meetings and emails are only a reflection of the underlying problems.

The answers would seem to include:

  • to consolidate proceedings rather than opening new ones,
  • not adding yet more ratesetting proceedings for specific add ons, and
  • funding intervenors on a more equitable basis with utilities and paying those groups sooner than two years after the relevant decision.

Some of these will require legislative action; others might be implemented after the current CPUC president has left. But it will only happen if intervenors collectively demand reform.

Will “optimal location” become the next “least-cost best-fit”?

At the CPUC’s first workshop on distribution planning, the buzz word that came up in almost every presentation was “optimal location.” But what does “optimal location” mean? From who’s perspective? Over what time horizon? Who decides? The parties gave hints of where they stand and they are probably far apart.

Paul De Martini gave an overview of the technical issues that the rulemaking can address, but I discussed earlier, there’s a set of institutional matters that also must be addressed. Public comment came back repeatedly to these questions of:  who should be allowed into the emerging market with what roles, and how will this OIR be integrated with the multitude of other planning proceedings at the CPUC? I’ll leave a discussion of those topics to another blog.

The more salient question is defining “optimal location.” I’m sure that it sounded good to legislators when they passed AB 327, but as with many other undefined terms in the law, the devil is in the details. “Least cost-best fit” for evaluating new generation resources similarly sounds like “mom and apple pie” but has become almost meaningless in application at the CPUC in the LTPP and RPS proceedings. Least cost best fit has just led to frustration for both many developers of innovative or flexible renewables such as solar thermal and geothermal, and for the utilities who want these resources.

SCE and SDG&E were quite clear about how they saw optimal location would be chosen: the utility distribution planners would centrally plan the best locations and tell customers. Exactly HOW they would communicate these choices was vague.

Many asked how project developers and customers might know where to find those optimal locations among the utilities’ data. Jamie Fine of EDF might have had the best analogy. He said he now lives in a house that clearly needs a new paint job, so painters drop flyers on his doorstep and not on his neighbors who’s paint is not peeling. Fine asked, “when will the utilities show us where the paint is peeling in their distribution systems?” His and others’ questions call out for a GIS tool that be publicly viewed, maybe along the view of the ICF tool recently presented.

I can think of a number of issues that will affect choices of optimal locations, many of them outside of what a utility planner might consider. The theme of these choices is that it becomes a decentralized process made up of individual decisions just as we have in the rest of the U.S. market place.

  • Differences in distributed energy resource characteristics, e.g., solar vs. bioenergy;
  • Regional socio-economic characteristics to assess fairness and equity;
  • Amount of stranded investment affected;
  • The activities and energy uses both of the host site, neighboring co-users/generators, and surrounding environs;
  • Differences in valuation of reliability by different customers;
  • Interaction with local government plans such as achieving climate action goals under SB 375.
  • Opportunities for new development compared to retrofitting or replacing existing infrastructure.

In such a complex world, the utilities won’t be able to make a set of locational decisions across their service territory simply because they won’t be able to comprehend this entire set of decision factors. It’s the unwieldly nature of complex economies that brings down central planning–it’s great in theory, but unworkable in practice. The utilities can only provide a set of parameters that describe a subset of the optimal location decisions. State and local governments will provide another subset. Businesses and developers yet another set and finally customers will likely be the final arbiters if the new electricity market is to thrive.

As a final note, opening up information about the distribution system (which the utilities have jealously guarded for decades) offers an opportunity to better target other programs as well such as energy efficiency and the California Solar Initiative. Why should we waste money on air conditioning upgrades in San Francisco when they are much more needed in Bakersfield? The CPUC has an opportunity to step away from a moribund model in more than distribution planning if it pursues this to its natural conclusion.

What are the missing questions in California’s distribution planning OIR?

The CPUC has opened a long awaited rulemaking to revisit (or maybe visit for the first time!) how utilities should plan their distribution investments to better integrate with distributed energy resources (DER). State law now requires the utilities to file distribution plans by next July. But the CPUC may want to consider some deeper questions while formulating its policies.

To date the utilities have pretty much been able to make such investments with little oversight. For one client, AECA, we submitted testimony pointing out that PG&E had consistently overforecasted demand and used that demand to justify new distribution investment that probably is unneeded. Based on a corrected forecast that recognizes that that PG&E’s (and the state’s) demand has turned downward since 2007, PG&E’s loads don’t return to 2007 levels until at least 2014. (We found a similar pattern in SCE’s 2012 GRC filings.)

 

AECA - PG&E 2014 GRC Testimony: Comparing Demand Forecasts

AECA – PG&E 2014 GRC Testimony: Comparing Demand Forecasts

Both PG&E and SCE justified new investment based on phantom load growth, but they would have been better served to show what investment might be required for the evolving electricity market. SCE has responded with the Living Pilot that tests out how to best integrate preferred resources.

The CPUC is relying on Paul De Martini’s More than Smart paper as a roadmap for the rulemaking. The CPUC has asked a number of questions to be addressed by September 4 with replies September 17. A workshop is to be held September 18.Beyond these questions, two more questions come to mind.

First, who will be allowed to play in the DER world? The OIR asks about non-IOU ownership of distribution lines, particularly related to microgrids, but it doesn’t consider the flip side–can utilities or affiliates participate in the DER market? Setting market rules in the face of rapid evolution and uncertainty, current participants will look to protect their current interests unless they are shown a clear opportunity to gain the benefits of a new market. The CPUC ignores the political economy of rulemaking at our risk.

The second is how is this proceeding to be integrated with the multitude of other proceedings at the CPUC that set various resource targets? The LTPP, energy efficiency, demand response and solar initiatives, along with others, all seem to run on parallel tracks with little in the way of interactive feedback. Megawatt targets seem to be set arbitrarily with little evaluation of comparative resource costs and effectiveness, and more importantly, how these resources might best integrate with each other. How are the utilities to adapt to the spread of DER if the CPUC hasn’t considered how much DER might be installed?

Both of these questions are about market functionality. Who are the likely participants? What are their incentives to act in different situations? How would the CPUC prefer that then act? How are price signals to be coordinated to create the preferred incentives? The system investment and operation rules are a necessary component of anticipating the market evolution, but they are not sufficient. California ignored the incentives of market participants in the previous restructuring experiment, at the cost of $20 to $40 billion. We should take heed of what we’ve learned from the past about the paradigm we should use to approach this impending change.

Looking beyond performance based ratemaking in New York’s Utility 2.0

Rory Christian of EDF has written about using performance-based ratemaking “+” (PBR+) in New York’s Reforming the Energy Vision proceeding. EDF, in taking an important step for an environmental advocate, recognizes the importance of providing the right economic incentives for market participants to achieve environmental goals. Prescriptive solutions too often are misguided and inflexible leading to failure and high costs.

That said, PBR+ may not be the best solution (and I don’t have the immediate answer to this question.) PBR hasn’t had a great track record in California. Diablo Canyon suffered from excessive costs that led to the push for restructuring. The competitive transition charge (CTC) opened the door for market manipulation. And the CPUC couldn’t say “no” when it awarded incentives for questionable energy efficiency gains. Other jurisdictions have had mixed results. Mechanism design is critically important to make PBR work.

Taking a step back from specific policy proposals, an important perspective to consider is that the “regulated utility” is not the same as “utility shareholders.” Shareholders are the true stakeholders in the discussion about the new utility business model. (Utility managers may hijack that role but that probably is not a sustainable position.) So we should be looking outside the box of standard regulatory tools, even PBRs, and ask “how else can utility shareholders see value from the electricity industry outside of their regulated utility affiliate?” There are potential models for alternative approaches that might ease the political and economic transition to the new energy future.

Chuck Goldman at Lawrence Berkeley National Lab made a presentation on the various business model options that are available. The Energy Services Utility (ESU) is an option that deserves greater exploration, particularly in concert with a distributed system operator (DSO). An ESU might provide a model for utility holding company shareholders to participate. But the devil could be in the details.

Guest Post: The importance of engaging electricity consumers

My partner at M.Cubed Steven Moss wrote this editorial for The Potrero View on how we need to engage consumers when developing a vision of how the electricity future might evolve:

Multiple corporate monopolies have emerged, thrived, and withered over the last hundred years. Railroads, telegram and telephone services, air transportation, network television and newspapers all had highly lucrative heydays, but were ultimately cut down to size by a combination of government anti-trust activities and new technologies. Today there’s a plethora of transportation, communication, information, and entertainment services, most offered at lower cost or with greater value than what was on the former cartels’ menu.
The societal conversation continues over how to best manage quasi-monopolies, like cable and Internet services. Water utilities are struggling with how to pay for themselves in an era in which reducing consumption is essential to addressing chronic scarcity. But the monopoly sector most ripe for rapid change is the almost a half-trillion dollar electricity sector.
Throughout the U.S. electricity is provided by a mix of municipal, cooperative, and investor-owned utilities (IOUs), each with a lock on delivering large aspects of the service in their home territories. In California the three large IOUs — San Diego Gas and Electric, Southern California Edison, and Pacific Gas and Electric (PG&E) — have carved up the lion’s share of the state’s monopoly electricity market. All of them face a business model that’s been buffeted by the rapid policy-driven onsite of renewables and the emergence of other technologies that aren’t as dependent on a large, capital-intensive spoke — fossil fuel or nuclear power plant — and wheels — transmission and distribution — system to operate.
Today, a home or business can install devices to capture sunshine or wind and cope with intermittent power flows by managing the timing of their energy consumption and installing a storage device, which could include harnessing the battery in the electric vehicle parked in the garage. These types of systems may work best when they’re combined at the multiple-neighborhood level, to create a portfolio of resources that can reduce the risk that the failure of one device will have catastrophic outage consequences. The optimal size for a next generation grid may be roughly half the size of San Francisco, a back-to-the-future system that mirrors the more than 100 small service providers that combined more than a century ago to create PG&E.
Institutional change is tricky, though, when it comes to electricity. Although rates are high in California, outside the Central Valley in the summer, household bills are generally modest as a result of the state’s mild climate. There’s solid service reliability, with the IOUs generally doing a fine job restoring post-storm outages. And, thanks to public policies, low-income families are provided substantial subsidies, while the grid has grown increasingly green. Outside San Francisco — and post natural gas-disaster San Bruno — where tilting at PG&E is an ideological battle rather than an economic one, these characteristics serve to mute the potential for widespread ratepayer revolt, and encourage consumer advocacy groups to protect the existing monopoly system.
Yet without change, electricity service is poised to get much more expensive, and probably less green. Renewable intermittency — production drops when the sun doesn’t shine — doesn’t match with the current system, creating gaps that could be plugged by costly and polluting fossil fuel power plants, eroding much of the environmental gains achieved over the past decade. Despite substantial technological innovation which should spur price competition, utility rates are consistently rising, in part because two competing paradigms — New Age renewables, and Industrial Age fossil fuels — are being simultaneously pursued for political reasons.
The seeds of a solution are in creating more knowledge. Consumers are almost entirely ignorant of how the timing of their electricity use influences costs. Electricity rates don’t reflect the underlying expense — to the environment or grid — of providing service in a given time and place. Since price-based feedback to the IOUs is significantly muted, the monopolies operate as if demand is largely immune to change, and must be met by increasing amounts of generation to ensure reliability.
The pathways we take as the grid wobbles in the face of renewable disruption will determine how much we pay, out of our pockets, and through dirtier air, for the next few decades. Fortunately, there’s a ready way to remold the monopoly electric utility industry: get the prices right. If rates reflected the true costs of service — including greenhouse gas and polluting air emissions — consumers and businesses would take action to change their consumption patterns, aided by high technology companies eager to solve profitable problems. The Internet of Things would become the Energy System of Things, with renewables, storage, and a host of communicating devices connected to optimize energy use in an environmental sustainable way.
Offering transparent electricity prices won’t solve all of the grid’s challenges. But not doing so walls off essential innovation. Renewables and emerging technologies, combined with clever tariffs, could help ensure that California never builds another fossil fuel power plant. The state can protect low-income households from onerous electricity bills, by directly paying for energy efficiency investments, or providing bill credits. A small is beautiful ethos can emerge to rival the large, reliable, monopolies in providing high-quality services. If we get the prices right.

Distribution system operator rising

Two recent papers propose a new approach to managing the distribution grid by creating a “distribution system operator” (DSO). The DSO would control the local low-voltage grid between the substations and the customers’ meters, much as the independent system operators (e.g., CAISO, PJM, MISO, NEISO, NYISO) run the high-voltage transmission grid above the substations. The transmission and distribution system would be run as an open-access system, much as how many natural gas utilities are run now.

Lorenzo Kristov and Paul De Martini have written about this approach, focusing on the technical issues. They are agnostic on ownership, and talking with Kristov (frequently) he sees that the DSO can be either owned by the existing utility or spun off.

Former FERC Chair Jon Wellinghoff and James Tong of Clean Power Finance have addressed the ownership / management issue, proposing that the DSO be independent. They also have proposed that regulated utilities be allowed to own distributed generation on the customer side of the meter.

An important issue yet to be addressed in the creation of (I)DSOs though is transition and sustainability. The creation of ISOs has been politically traumatic, and creating IDSOs will face even more risk-averse political opposition, particularly in the West, after the energy debacle of 2000-01. We’ve also seen that ISOs are not particularly cost sensitive because they are largely insulated from direct cost regulation of the capital assets that they manage (a classic “agency” problem.) Since transmission is such a small portion of overall rates, the ISOs have been able to fly under the radar–but that may change soon.

Finally, it’s not clear how shareholders will view the change in asset ownership, management and returns. I wrote about this previously in the emergence of the “peer to peer” economy. Ensuring that shareholders don’t lose substantial value, even as the risk profile changes, will be key to easing the political process. There are alternative models for easing the asset management transition that is not threatening to current shareholders. There are better models than simply relying on regulated utilities to essentially do more of the same. Market forces are important in driving the innovation needed to transition the electricity system.  More on that another time.

What is the true price for renewable energy power?

The renewable energy market has been in upheaval since the collapse of the financing sector in 2008. The withdrawal of easy money and uncertainty over federal tax policy has increased perceived risk.  Large firms have been shedding renewables subsidiaries and promising newcomers have dropped high-profile projects. Waste Management just sold Wheelabrator, exiting the waste-to-energy market. Brightsource suspended its Hidden HIlls solar thermal project. Much of this activity is driven by the perception that wholesale electricity market prices are falling and the underlying fundamentals will lead to further declines.

This perception is misplaced, however. Short run electricity market prices are falling as natural gas becomes cheaper, and more importantly, fossil fuel generation is squeezed out by increasing renewables and falling demand. However, the electricity marketplace hasn’t yet adjusted to the fact that natural gas generation is no longer the only marginal generation resource. In California, the renewables portfolio standard (RPS) makes at least 33% of the marginal generation from renewable resources. When capital costs are correctly figured in, and more long-term contracts are offered to match those deferred resources, power purchase agreement (PPA) prices for the right types of resources should increase, not decrease.

The problem is that the industry hasn’t been able to adjust its procurement model to reflect this new reality. I think this is coming from a combination of utilities continuing to maintain their monopsony (single buyer) position, risk averse regulatory agencies still relying on an obsolete procurement regulatory process, and those agencies enforcing the monopsony power of the utilities in the name of protecting ratepayers. This may not change until there is public acknowledgement that this situation exists. The difficulty is finding the right stakeholders with enough sway to raise the issue.

Repost: California Dream – How Big Data Can Fight Climate Change in Los Angeles

EDF and UCLA have created an interesting visual presentation on the potential for solar power and energy savings in the LA county, overlaid with socio-economic characteristics. (But I have some trouble with the representation of a few West LA communities as disadvantaged with high health risk–is that the UCLA campus?

What we might expect for diffusion of new decentralized energy technologies?

Technologies and policies that enhance the development of decentralized energy resources have generated increasing interest over the last couple of years.  I’ll write more in the future about what are the underlying drivers, both technological and institutional.

I’ve been interested in the question of where do we stand, and how long might it take for diffusion of these new technologies. We can look back and see how technology transformed lives in just a couple of decades. Compare kitchens from 1900 and 1930; if we walked into the earlier kitchen, most of us would be lost, but we could whip up a meal in 1930.

 1030's Kitchen; Photo Credit - Henry Ford Museum

Or the rapid adoption of autos. In 1909, people could stand in the middle of Pike Street in Seattle and talk:

File:Seattle - Pike Street 1909.jpg

Not so safely in 1930:

Do we stand today at a point just at the onset of a new technological evolution?

One question to be answered is whether our institutional settings will allow these new technologies. In one case, it appears that Germany has already chosen its road. But in the US, whether we rely on central power stations using transmission lines may still be a question in play. That deserves a separate post of its own.

If we assume that we choose the decentralized path, what might we expect in when these technologies are adopted widely. A couple of graphics illustrate historic diffusion rates. This is one from VisualEconomics via The Atlantic:

Another one from Forbes via The Technium shows the parallel development paths (however, I don’t like starting at the year of invention instead of a threshold adoption level):

One might interpret the upper graph as showing accelerating adoption rates. But I interpret the lower chart as illustrating at least two factors that drive diffusion: the relative importance of network infrastructure and the expense relative to individual wealth.  Autos, telephones and electricity all required construction of a large network of roads or wires, often funded with public investment. Individuals can’t choose to adopt the technology until a larger public decision is made to facilitate that adoption.  As to expense, refrigerators and dishwashers were large household investments for many years, and cars are still a large single expenditure. On the other hand, cell phones, radios and televisions quickly became inexpensive which lubricated diffusion. We need another graphic showing how diffusion rates relate to these two different axes.

We are still unsure where decentralized energy technologies will fall among these characteristics. They may seem small and inexpensive, but enough solar panels to power a house will still be several thousand dollars for the foreseeable future. And the how much electric network investment is required to integrate these resources is the center of the debate over technology policies.

Too often studies making forecasts and policy recommendations don’t consider what adoption rates are feasible or probable. However a study comes along and incorporates this concept as its centerpiece. A good example is the Clean Energy Vision Project’s Western Grid 2050 report. Lead by a former colleague Carl Linvill, who’s now at the Regulatory Assistance Project, it looked at several different scenarios for technology diffusion. Such studies give us a better understanding of what’s actually possible rather than what we wish for.

 

Making Community Solar Gardens Work

California has been quite successful at encouraging the development of (1) large utility-scale renewables through the renewables portfolio standard (RPS) and other measures and (2) small-scale, single structure solar generation through the California Solar Initiative (CSI) and measures such as net energy metering (NEM).  However, there have been numerous market and regulatory barriers to developing and deploying the “in-between” community-scale and neighborhood-scale renewables that hold substantial promise.

Community-scale and neighborhood-scale distributed generation (DG) includes some technologies that simply are not cost-effective at the small scale of a single house or business, but are not large enough to justify the transaction costs of participating in the larger wholesale electricity market.  These resources, such as “community solar gardens”, can meet the demands of many customers who cannot take advantage of adding renewables at their location and can also reduce investment in expensive new transmission projects. Examples of these types of projects are parking structure-scale solar photovoltaics, solar-thermal generation and space cooling, and biogas and biomass projects, some of which could provide district heating.  Technology costs are falling so rapidly that these mid-scale projects are becoming competitive with utility-scale resources when transmission cost savings are factored in. SB 43 (Wolk 2013) recognizes that the promise of mid-scale renewables has not been realized.

In response to SB 43, each of the large investor-owned utilities–PG&E, SCE and SDG&E–have filed proposed tariffs with names such as Enhanced Community Renewables Program or Share the Sun. I filed testimony in the PG&E and SCE cases on behalf of the Sierra Club addressing shortcomings in those programs that would inhibit development of community solar gardens. SDG&E’s proposal, while not perfect, better meets the law’s objectives. After the hearings, the CPUC postponed a proposed decision from the July 1 deadline to October.

SB 43’s requirement that the investor-owned utilities “provide support for enhanced community renewables programs” is a critical step forward for California’s distributed energy goals.  The CSI is the state’s premier distributed generation program.  In SB 43 the Legislature expressed its intent that the “green tariff shared renewables program seeks to build on the success of the California Solar Initiative by expanding access to all eligible renewable energy resources to all ratepayers who are currently unable to access the benefits of onsite generation.”  SB 43 advances the success of the CSI into the area of multifamily residential and multitenant commercial properties and introduces all types of renewable energy resources.  Customers who, for various reasons, cannot benefit from the current net metering programs, will be able to benefit through SB 43.

The Legislature clearly intends for this program to lead to a transformation in the energy market akin to the success for single customers of the CSI. This necessary market transformation extends to multifamily and commercial lease properties that are currently beyond the CSI and Self Generation Incentive Programs (SGIP). The Commission should ensure that utilities’ programs under SB 43 provides the market transformation that is necessary for this underserved segment.

State regulations calls for all new residential dwellings to consume zero-net energy (ZNE) by 2020, and all new commercial properties by 2030.  Fully implementing the market transformation identified in SB 43 is one of the obvious means to achieve this target.  The CSI option has already facilitated many examples of feasible ZNE single-family homes using renewables well ahead of the 2020 deadline.  There are several market barriers to integrating renewables in a similar manner on multifamily and commercial leased properties and on single-family that are not favorably located or that have other impediments.

A properly-designed community solar garden program should provide a critical work-around for the split-incentive problem that has plagued local renewable development in California.  The split-incentive problem arises from the fact that multi-tenant structures, both commercial and residential, may not be able to implement solar or other renewable resources due to the fact that lessees are not the owners of the shared space where renewables could be sited.  The problem of split-incentives between landlords and tenants has long been recognized, and has been the focus of energy efficiency programs.

As a corollary, the Commission should provide individual developers and property owners the opportunity to integrate energy efficiency and DG measures to achieve the best mix for meeting environmental and economic goals. Each project is unique so that a “one size fits all” approach that requires sale of all output into the wholesale market with buyback from customers who may have no connection with the project will only discourage enhanced development.

For distributed generation to expand in California there must be a cost-effective path for residential and commercial tenants, as well as not-well-situated buildings, to install solar and other renewables and share the costs among other customers. The focus to date has been on either utility-scale or single-building scale projects, but the most promise may be in mid-scale projects that can serve a community or a neighborhood cost-effectively through a combination of scale economies and avoided transmission and distribution investment.  But to achieve this objective requires changes from current utility practices.

An update: Here’s the link to the decision on this CPUC case issued in January. And here’s the link to scoping memo for the phase of this proceeding.