Tag Archives: energy resources

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.

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?