Tag Archives: alternative energy

Looking at a locality’s options as the energy marketplace changes

Here’s the first in a series of articles that I am coauthoring about how the new direction in the energy utilities marketplace can affect the choices for a locality like the City of Davis. This one is with Gerry Braun. This first article reviews the findings of study conducted last year that focused on a more traditional utility models, and then sketches the most salient options. This and future articles with other co authors will include:

  • What are the options going forward for Davis and what have we looked at.
  • Describing decentralized energy systems
  • How a decentralized energy system might fit into achieving local goals (e.g., climate action plan) and affect economic activity.
  • Barriers to achieving local goals in this future scenario.
  • Comparisons of potential business models to overcome those barriers.

The (telecom) path well travelled: What does it hold for electricity?

In many ways, the potential for a dramatic transformation in the electricity industry feels like deja vu in the telecommunications industry of the 1980s. That industry evolved rapidly and radically so that what we see today is almost unrecognizable compared to three decades ago. Do we stand on the verge of a similar revolution in electricity?

In the 1980s, it was the entry of microwave transmission that threatened the hardwired long-distance network of AT&T. The combination of the MCI decision allowing competition and the DOJ anti-trust settlement that broke AT&T into the 7 Baby Bells, both in 1982, led to proliferating long distance competition.

The electricity industry had a similar transformative decision in FERC Order 888 in 1996. There was a similar first wave of opening up wholesale competition through a centralized grid through restructuring induce by the introduction of combined cycles. As with AT&T being slow to adopt new technologies, it’s hard to imagine the electric utilities building CCGTs before others forced their hands.

In telecom, allowing more players meant that they started to compete with customers using new technologies, Rapid innovation in computers bled over to phones and cell phones. The FCC facilitated this with innovative auctions of regional wireless band licenses. The entry of cable companies for local service created more competitive pressure. Yes, the industry went through consolidations, but the threat of entry and marketing innovations place caps on what these companies can charge and force more consumer options.

Long distance competition may not have benefited, but such an assessment ignores the second wave of telecom deregulation starting a decade later: the entry of cable companies, the use of the Internet for calling, the rise of messaging, and proliferation of smart cell phones. Now AT&T’s land lines are an afterthought for phone service and those companies offer bundles of services across telephone, television, Internet and cell phone. Long distance and local land line competition are but an afterthought in the industry after three decades. The better question is whether these services will even survive in the near future.

Electricity restructuring may not have delivered on its initial promise, but, as with telecom, it brought new competitors who are looking for different ways to enter market. New technologies that decentralize energy resources look like the second wave of telecom innovation in many ways. NRG is one such example of a company that focused on merchant generation but are now looking to distributed energy resources. Sempra and Duke are utility holding companies that are shifting their mission in promising ways. Will these and other innovators break into the energy services market and offer consumers the type of choices that telecom customers now have? Will the existing modes of delivering electricity lose dominance in the same way as happened in telecom?

The answer will depend in part on decisions made by regulators. The US DOJ and FCC played key parts, and the state commissions eventually backed away from close regulation. This requires support from stakeholders including the utilities. AT&T eventually evolved into a dominant player in the new marketplace although it wasn’t a smooth transition. Will the electric regulators have similar foresight? Will they avoid many of the same pitfalls?

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.

Retrospective on restructuring and what it means for our future

Jim Bushnell of UCD and the Energy Institute at Haas has posted about a paper he is coauthoring with Severin Borenstein looking back 20 years at restructuring. It has some interesting insights, but I take issue with a couple points about the original motivation for restructuring, and whether we will be left with legitimate stranded costs with the current transformation.

My comment on the post:

The rationale behind restructuring (as reflected by my agricultural and industrial clients at that time) of “never again”–the utilities had demonstrated an inability to contain costs in constructing Diablo Canyon, SONGS and Helms, and FERC had gutted the ability for third parties to build turnkey plants in the BRPU decision. The utilities were very slow to adopt the low-cost combined cycle technology, so the only solution looked to be to walk away. Restructuring did establish the merchant industry which has been the leaders in developing renewable technologies and even rooftop solar. Again, we could have expected the utilities to drag their feet, so we have gotten institutional innovation that otherwise would not have happened. (Institutional innovation, not technological, is what got us reduced SOx emissions under the Clean Air Act Amendments of 1990.)

Going forward, leaving the utility system only “strands” network infrastructure if we take the static view that the network will continue in its current state. Shareholders are still recovering their investment, and if they’ve been paying attention since 2007, they should know that overall demand has been falling. They will only be stuck with infrastructure costs if either they have had little foresight or if a sudden technological change accelerates customer exit. In the latter situation, this will only occur if distributed resource costs fall dramatically in which case the exit will probably be socially beneficial. Why should consumers be locked into a large scale network to protect shareholders?

Restructuring was marked by a sudden, dramatic change–opening the market on a single day, divesting generation assets within a few months. The current transformation is more gradual because it is house by house, business by business. Utilities can change their investment plans, and depreciation recovery allows them to recoup their past costs. We may be foregoing the benefits of a paid-up network, but we have almost never regretted such technological change in the past. (Maybe the sale of the “red cars” rail system in LA as the most salient exception.) Do we regret that we’ve left behind land lines for our cell phones? Given the benefits of carrying around microcomputers for daily activities, I think not.

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?