Tag Archives: California

Assessing the economic impacts of drought regulations

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M.Cubed was asked by the State Water Resources Control Board to prepare an economic assessment of the emergency regulations ordered by the Governor to reduce municipal water use by 25%. We gathered a team that included Roger Mann of RMann Economics, Tom Wegge of TCW Economics, Richard Howitt and Duncan MacEwan of ERA Economics, and prepared the report in about two weeks. The SWRCB included a summary of those findings in its regulatory digest.

The innovative aspect of our study is to steer away from a single point probabilistic estimate of the benefits of the regulations and instead to focus on the potential vulnerability and consequences of the risk of continued drought in the future.

The EO is intended to address potentially significant economic vulnerabilities – risks – rather than statistical or probabilistic expectations. If the drought and high temperatures continue in California, water saved as a result of the order will become increasingly valuable. Under these circumstances, costs estimated to be associated with the EO this year could be more than exceeded by greater adverse impacts next year if the EO had not been issued.

Australia had an extended drought that lasted 10 years before ending in 2012 that cut 1.6% off its GDP. For California that would be $35 billion in a single year which is multiples of the range of costs we estimated for the regulations. In other words, the probability of continued drought would have to be less than 4% to make this option uneconomic.

We also pointed out that while the water utilities will lose revenues this year, as mostly public agencies, they will have to make up those losses in the future. For this reason, those revenue losses should be treated as eventual economic costs.

Legal Planet: California Supreme Court to review San Diego SB 375 climate change ruling

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I blogged earlier on the implications of this case. The UCLA/Boalt Law Schools blog Legal Planet has more on this review.

Energy at Haas: One university’s attempt to reduce energy waste at work

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A look at how commercial and institutional building energy use can be reduced by providing price signals.

PG&E to release 65,000 emails since 2010

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PG&E in the wake of more revelations about ex parte contacts with CPUC commissioners and staff is releasing 65,000 emails over the period from 2010.  This should make for some interesting reading by interested parties. Is there anyone out their who might like to cooperatively compile a readable database?

SANDAG, Executive Orders and California Policies

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In a rather earthshaking ruling, California’s Fourth District Court of Appeals ruled that the San Diego Association of Governments (SANDAG) must comply with the Governor Schwarzenegger’s Executive Order S-3-05 to “by 2050, reduce GHG emissions to 80 percent below 1990 levels.” SANDAG had completed its 2050 Regional Transportation Plan using AB 32 as its primary compliance hurdle. AB 32 “requires California to reduce its GHG emissions to 1990 levels by 2020.” SB 375 required that metropolitan planning organizations (MPOs) such as SANDAG develop sustainable community strategies (SCS) that reduce GHG emissions by an amount allocated by the California Air Resources Board to each MPO.  SANDAG’s RTP is its SCS.

This is the first time that an EO has been held at legally binding on local agency actions. Governors have issued plenty of EOs before but they’ve been taken as providing policymaking and rulemaking guidance to the Governor’s appointees in various agencies. This decision raises the question whether those other EOs will now carry much more weight? And if governors issue conflicting EOs, which one is currently in force? What if an EO conflicts with state law passed by the Legislature?

On climate change, governors have issued seven such EOs. The Governor recently issued an EO calling for substantial water use reductions in the drought. Is the EO from 2008 still in force?  The Energy Action Plan EO from 2004 calls for several specific actions by state agencies, many of them undertaken but necessarily on the timeline specified. Should the 33% renewable portfolio standard (RPS) be implemented along the lines of state law or the EO? A bit of research could show many more of these types of examples.

SANDAG is appealing the decision the State Supreme Court. How various interests align will be interesting.

Questions yet to be answered from the CAISO Symposium

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While attending the CAISO Stakeholder Symposium last week I had rush of questions, not all interconnected, about how we manage the transition to the new energy future. I saw two very different views about how the grid might be managed–how will this be resolved? How do we consider path dependence in choosing supporting and “bridge” resources? How do we provide differential reliability to customers? How do we allow utilities to invest beyond the meter?

Jesse Knight, former CPUC Commissioner and now chairman at SDG&E and SCG, described energy utilities as the “last monopoly” in the face of a rapidly changing economic landscape. (Water utilities may have something to say about that.) SDG&E is ahead of the other utilities in recognizing the rise of the decentralized peer-to-peer economy.  On the other hand, Clark Gellings from EPRI described a world in which the transmission operator would have to see “millions” of nodes, both loads and small generators, to operate a robust network. This view is consistent with the continued central management implied by the utility distribution planners at the CPUC’s distribution planning OIR workshop. At the end of the symposium, 3 of the 4 panelist said that the electricity system would be unrecognizable to Thomas Edison. I wonder if Alexander Graham Bell would recognize our telecommunications system?

One question posed to the first “townhall” panel asked what role natural gas would have in the transition to more renewables. I am not aware of any studies conducted on whether and how choices about generation technology today commits us to decisions in the future. Path dependence is an oft overlooked aspect of planning. We can’t make decisions independent of how we chose in the past. That’s why it’s so difficult to move away from fossil fuel dependence now–we committed to it decades ago. We shouldn’t ignore path dependence going forward. Building gas plants now may commit us to using gas for decades until the financial investments are recovered. We may be able to buy our way out through stranded asset payments, but we learned once before that wasn’t a particularly attractive approach. Using forethought and incorporating flexibility requires careful planning.

And along those lines in our breakout session, another question was posed about how to resolve the looming threat of “overgeneration” from renewables, particularly solar.  Much of the problem might be resolved by charging EVs during the day, but it’s unlikely that a sizable number of plug-in hybrids and BEVs will be on the road before the mid-2020s. So the question becomes should we invest in gas-fired generation or battery or pumped storage, both of which have 20-30 year economic lives, or try to find other shorter lived transitions including curtailment contracts or demand response technologies until EVs arrive on the scene? It might even be cost effective to provide subsidies to accelerate adoption of EVs so as to avoid long-lived investments that may become prematurely obsolete.

Pricing for differential reliability among customers also came up. Often ignored in the reliability debate at the CAISO is that the vast majority of outages are at the distribution level. We appear to be overinvested in transmission and generation reliability at the expense of maintaining the integrity of the local grid. We could have system reliability prices that reflect costs of providing flexible service to follow on-site renewable generation. However the utilities already recover most of the capital costs of providing those services through rate of return regulation. The market prices are suppressed (as they are in the real time market where the IOUs dump excess power) so we can’t expect to see good price signals, yet.

Several people talked about partnerships with the utilities in investing in equipment beyond the meter. But the question is will a utility be willing to facilitate such investments if they degrade the value of its current investment in the grid? Fiduciary responsibility under traditional return on capital regulation says only if the cost of the new technology is higher so as to generate higher returns than the current grid investment. That doesn’t sound like a popular recipe for a new energy future.  Instead, we need to come up with creative means of utility shareholders participating in the new marketplace without forcing them down the old regulatory path.

Margaret Jolly from ConEd noted that the stakeholders were holding conversations on the new future but “the customer was not in the room.” Community, political and business leaders who know how electricity is used were not highly evident, and certainly didn’t make any significant statements. I’ve written before about offering more rate options to customers. I wanted to hear more from Ellen Struck about the Pecan Street study, but her comments focused on the industry situation, not customers’ behaviors and choices.

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

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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.

Understanding the Challenges of Modeling AB 32 Policy

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A summary of the review of the AB 32 Scoping Plan we conducted in 2008 for EDF.

clotworthy's avatarEnvironmental & Energy Valuation News

The Aspen Environmental Group, M.Cubed for Environmental Defense / by Richard J. McCann
http://www.edf.org/documents/8902_AB32%20EconModeling%20M3%20final.pdf (full report)
http://www.edf.org/documents/8901_AB32%20AspenEnv%20Modeling%20PolicySum.pdf (summary)

[From press release] A new study released today concludes that state-of-the-science economic models, including those used for the California Air Resources Board’s economic analyses of California’s Global Warming Solutions Act (AB 32), are not capable of simulating the fundamental changes in California’s economy that AB 32 measures are likely to cause. While critics of ARB claim that costs might be underestimated, this new study shows that many benefits also are not represented by models and more modeling isn’t as useful as consideration of lessons from prior policies and economics literature.

The study is timely because CARB will vote on the Proposed Scoping Plan to implement the Global Warming Solutions Act of 2006 (AB 32) on December 11, less than a week away.

In the new study, Dr. McCann reveals that current techniques…

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Rethinking the rates that utilities offer to customers

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I just got back from an annual conference put on by the Center for Research in Regulated Industries. It brings together many of the applied economists and policy analysts working in California’s electricity industry. I presented a paper on reconsidering rate design.

Customers are often left out of the conversation about how to move forward into the new energy future, as they were at the recent CAISO Symposium where not a single customer representative was included in the “Town Hall Meeting.” Current retail rate tariffs seem to be designed with little thought about how customers would prefer to pay for their energy, and what might best encourage consumer energy management. And when customers are asked to take on more risk or cost to address energy needs, their revenue responsibility is often unchanged.

How should utilities align their rates and tariffs to fit customers’ preferences? Utilities both face a rapidly evolving energy marketplace and have available to them a larger portfolio of technologies to provide more services and to measure usage across different dimensions. One important step that utilities could take is to offer customers the same variety of contracts as the utilities make with their suppliers, so that rates mirror the power market.

Customers have a range of preferences, and some prefer to be more innovative or risk takers than others. To better match the market, should utilities offer a range of tariffs, and even allow customers to construct a portfolio of rates that allow a mix of hedging strategies? How should the costs be allocated equitably to customers to reflect the varying risks in those portfolios? How should the benefits of lower costs be allocated between the active and passive customers? The new metering infrastructure also provides opportunities for different billing strategies.

How should time varying rate (TVR) periods be structured to adapt to the potential shift over time when peak meter loads occur? Should the periods be defined by utility-side resources or the combination with customer-side resources? Is the meter an arbitrary division for setting the price? What is the balance between rate stability to encourage customer investment versus matching changing system costs? Should the utilities offer different TVR periods depending on the desired incentives for customer response?
In developing costs, how should utilities and commissions consider how resources are added, and in what capacity? Renewables are now part of the incremental resources for “new” load, and we can no longer rely on the assumption that fossil fuels are the marginal resource 100% of the time.

The “super off-peak” rate offered by Southern California Edison (SCE) to agricultural customers is one example of how a rate can be constructed to encourage customer participation in autonomous ongoing energy management. Are the incentives appropriate for that rate? Over what term should these rates be set given customer investment?

If you’re interested in this paper, drop me a line and I’ll send it along.

The Elusive Potential of California’s Water Supply

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NRDC and the Pacific Institute just released a report purporting to show the potential for large water savings in California in the face of our severe drought. While laying out the technical potential in a static setting is a useful exercise, this report can be misleading about the true potential for water savings without significant institutional and political change. The report doesn’t account for how farmers actually respond to improved irrigation efficiencies, and how residential customers resist changing their landscapes and using recycled water.

Starting with farmers, we found in a study on the benefits of aggregating PG&E’s agricultural accounts that growers were using subsurface drip systems increase tomato yields by as much as 50%. In Fresno County, processed tomato yields have risen 26% in 5 years as flood irrigation has been replaced by drip. In addition, the amount of runoff has been reduced, so on net the new efficient irrigation technologies have lead to increased productivity with no reduction in water use.

Residential customers are resistant to the idea that they should give up their lush landscaping. As I posted previously, even in environmentally-friendly Davis, voters rejected a new rate structure that would have encouraged summer water conservation. And they are just as thrilled with using recycled water. A 2004 SDCWA survey found that 63% of residents didn’t want recycled water introduced into their drinking water. All of this adds up to political resistance to change that water professionals see as a “no-brainer.”

Another question is what happens to the downstream and groundwater basin users who now depend on runoff for their water supplies? Particularly in agriculture, water is often reused several times as it drains or percolates to the next user. Calculating the true potential savings requires a full water-budget analysis of a basin, not just adding up all of the individual savings without considering the synergism among them.

And finally, what happens to the ability to respond to variations in water conditions? Urban water agencies are already concerned about “demand hardening.” Farmers have moved to higher yield, more profitable orchard crops, but as a result they can’t easily accommodate large swings in water availability. Managing our water supply isn’t just about reducing the average consumption–it’s about creating a less vulnerable system.