While Uber is not currently offering peer-to-peer ride-sharing, the CPUC agreement allows for “drivers not specifically licensed to drive a limousine or taxi” to provide rides, which could include Uber’s drivers, the company notes. And Uber wrote that it could pave the way for ride-sharing in the future.

Update: As TechCrunch first reported and Uber later confirmed with us, the company plans to expand into ridesharing, although it has no immediate specifics to announce. “It would be natural to expect us to go into competition,” an Uber spokesman said.

Lyft’s parent company Zimride announced Wednesday that it had entered into an agreement with the state where the CPUC would drop its earlier cease-and-desist order and fine against the company. Lyft wrote in a blog post that the company has worked to improve safety measures, increasing liability insurance and performing background checks on drivers, and is pleased the state will let them continue operating for the time being:

“This agreement supports the continued legal operation of Lyft and sets a precedent for the upcoming rulemaking process. This agreement would not have been possible without the outpouring of support from the community,” wrote the company co-founders.

Uber announced Thursday that they also have reached an agreement with the CPUC over the company’s technology used to hail rides and has confirmed that its legal in California:

“This settlement agreement is part of a steady drumbeat of progress in which pro-consumer, pro-innovation jurisdictions like Washington D.C., New York City, and Massachusetts are recognizing that everyone wins when new technology that fosters efficiency, affordability, and choice in transportation is allowed to flourish. California has always been on the cutting edge. The CPUC agreement further demonstrates how the Golden State welcomes and supports not only technological advancement, but a better future for drivers, riders, and our cities.”

Rideshare and next-generation taxi companies like Uber and Lyft have struggled to gain acceptance in cities across the country even as users embrace their services, with Uber facing regulatory challenges in D.C., push-back from cab drivers in San Francisco and Chicago, and earlier problems in the more stringent New York City market. With Lyft and Sidecar, questions revolved around how the companies would properly insure drivers and riders.

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The staff of California Public Utilities Commission is recommending a “no” vote for two power purchase agreements in which SCE will buy power from BrightSource’s yet-to-be-built Rio Mesa solar project. The staff said the two agreements are too expensive and noted that the power plants for the contracts won’t have ways to store electricity for later use. The three remaining power purchase agreements between the two companies involve other power plants that will have energy storage, which will give Edison more flexibility to manage supply and demand.

The commission was originally scheduled to vote on the five power purchase agreements today but opted to postpone the decision until next month. The postponement request came from commission president Michael Peevey, who often pushes and wins approval for controversial projects from his fellow commissioners by coming up with alternative proposals that contain compromises.

The commission staff said in the report that storage is a “unique attribute” that “decreases renewable integration risk and provides more value to ratepayers.” With energy storage, a utility could bank electricity when demand is low and release the power when demand is high. It makes a solar power plant act more like conventional fossil fuel power plants, which can produce power any time of the day. California utilities are under mandates to increase the amount of renewable energy they serve to their customers, and they are turning to solar and wind energy to meet the requirements.

Solar and wind farms only produce power when the sun is out or the wind is blowing, so they won’t be able to send electricity to the grid consistently in ways that fossil fuel power plants can. An electric grid runs smoothly when there is a balance of supply and demand, however, and that makes managing solar and wind energy a tricky business. The ability to bank solar or wind electricity will help solve this dilemma. In fact, the commission is considering whether to require utilities to pay for energy storage as more solar and wind energy flows into the grid.

The cost of adding energy storage doesn’t always make sense, especially in the case of using newer storage technologies, such as batteries. But it does for BrightSource, which announced last August that it would start designing storage into its power plants. The Oakland company then revealed last November that it would add energy storage in some of the power plants that would serve Edison’s customers. The announcement mentioned three contracts to sell power to Edison, the same contracts that are now under review by the commission.

Edison actually sought approval for all five contracts back in 2009, when energy storage played no part. Then it re-negotiated the contracts with BrightSource in 2011 after BrightSource had modified those power plant proposals to reduce their environmental impact.  This time around, energy storage made its way into three of the contracts.

The two contracts that won’t benefit from storage are part of the proposed Rio Mesa project, which is under review by California Energy Commission. BrightSource applied for Rio Mesa’s approval last October, and ideally it would have approved contracts to sell power from the project in hand once it gets the permits to build it. Lining up those contracts also will be important for convincing investors to finance the project.

BrightSource plans to use tanks of molten salt for storing the thermal energy produced by its fields of mirrors. The mirrors concentrate and direct sunlight to heat up a water-containing boiler atop of a tower. The steam from the heated water runs the turbine and generator to produce electricity. If the steam isn’t going to be used to generate electricity, then it will be piped to heat the molten salt, which is good at trapping heat. Power plant operators can then use the hot molten salt to produce steam for electricity generation whenever that is needed.

BrightSource isn’t alone in finding out the necessity of offering storage to attract utility customers. Areva Solar told me a few months ago that it had finally decided on using molten salt for storage for its power plants. Areva also uses mirrors to harness the sun’s heat to produce electricity, but the mirror and power plant design is quite different from BrightSource’s.

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The report by CalCEF, a San Francisco nonprofit for promoting clean energy research and investments, looks at California homes partly because the state has 8.4 million, or over 10 percent of the nation’s single-family homes, which in turn account for 85 percent of the carbon emissions from residential properties. The report also ties energy efficiency policy to economic development and argues that good energy efficiency programs will boost incomes and lift the depressed housing market, where one in three homes had sale value that was lower than the mortgage.

Regardless of whether energy efficiency programs can achieve those larger goals, figuring out more effective ways to raise public awareness and create more energy efficient homes are already worthy goals on their own. California has been putting in rules to force appliances and electronics manufacturers to roll out more efficient products since the late 1970s, and it requires the investor-owned utilities to put energy efficiency programs in place. Regulators like to point out that California is the most energy efficient state per capita.

A ranking by the American Council for an Energy-Efficient Economy last year put California in second place for its energy efficiency initiatives. Energy efficiency upgrades typically involve installing windows and other equipment that better insulate homes and use less energy to perform the same functions. While the work isn’t high tech, there are certainly opportunities for better software to audit energy use, streamline and improve the sales and installation work and monitor the results.

More can be done, the CalCEF report says, because roughly two out of three homes in California were built before better building codes that promote energy efficiency were in place in late 1970s. The best time to catch homeowners’ attention is when they are renovating or selling their homes, or when they are charging higher rates for increasing their electricity use (many utilities charge a baseline rate for a certain amount of usage and then higher rates for the energy used above that baseline). Here are some other recommended actions:

1. Show me the numbers. Homeowners should be required to disclose the energy cost of their homes while they sell their houses, and real estate listings should include that information as well. California also should come up with a system to rate how energy efficient each home is and include that information during real estate transactions.

2. Mandate efficiency retrofits. San Francisco and Berkeley have regulations requiring single-family homes to undergo an energy efficiency retrofit during their life time. Something similar should be implemented statewide and force homeowners to make their homes more energy efficient when they are selling homes or taking out permits to renovate them. There could be a list of energy efficiency measures that must be completed, or a mandate that whatever upgrades are taken will achieve certain measurable results.

3. How to pay for it. Energy efficiency advocates like to point to studies showing that more energy efficient homes can command higher selling prices. Still, California Public Utilities Commission estimates that a homeowner will have to spend an average of $7,200 to make his or her home 25 percent more energy efficient. CalCEF is advocating financing options beyond the typical use of credit cards and home equity loans. One program that has gotten a lot of support among clean power proponents is to fund retrofits through municipal bonds, and homeowners re-pay the costs through property tax payments. The idea isn’t new, but it’s not widely available. Sacramento is among some of the cities that have tried or are considering this financing option.

Another way to lower spending is to pool purchasing of retrofit equipment and services. This can be done through some kind of associations or even business that aggregate projects in order to negotiate better prices. CalCEF’s report also recommends offering incentives to reduce, say, permit fees or home sale closing costs, as ways to entice homeowners to undertake efficiency upgrades.

Photo courtesy of SolarCity

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The bill, SB 843, aims to enable people who don’t own homes, or own homes that don’t have suitable roofs for solar panels, to buy clean power and offset their utility bills. They could sign contracts with owners of solar power projects for a portion of the power produced, and the amount they pay for would show up as credits on their utility bills. The proposed program would be available not only to consumers but also businesses who are customers of the three big investor-owned utilities.

“We believe it’s possible for everyone to buy renewable energy and save money from day one and do it without state subsidies,” said Tom Price, director of policy and market strategy at San Francisco-based solar power project developer CleanPath, which has helped to draft the bill’s language.

The Senate has passed the bill, which is making its way through the Assembly, and it could land on Gov. Jerry Brown’s desk by the end of August, Price said. The legislation would create a 2 gigawatt-sized program.

California already runs several incentive programs to subsidize solar installations at homes and businesses. At over 1 GW, the state has more solar electricity flowing from these residential and commercial rooftops than any other state in the country, according to a report issued by the California Public Utilities Commission on Monday.

Just for the wealthy?

But SB 843’s proponents say the state can do more because many of its residents aren’t able to take advantage of the rebate programs. There is a perennial debate over whether the programs are benefiting mostly wealthier residents. They can afford to pay the expensive solar electric systems out right, or have the good credit scores to borrow money to finance the installation. Since installers tout energy savings in their sales pitches, they target people who use a lot of energy and pay high electric rates.

The state’s programs do include subsidies for low-income housing, however, and the latest data show that solar is becoming more affordable for average consumers. The number of solar systems installed in the low-income market, in which the median incomes is less than $50,000, has increased by 364 percent since 2007, the new commission report said. The installation figure for the middle-income market, in which the median income runs between $50,000 and $100,000, has jumped 445 percent during the same period. The majority of the incentive applications received by the state in 2011 came from this middle-income segment.

The program created by SB 843 wouldn’t be eligible to use money that’s budgeted for existing solar incentive programs, Price said. Project developers could still claim a 30 percent federal investment tax credit, which is good through 2016. Each project can be as large as 20 MW, a size that is meant to provide an economy of scale to keep its development and construction costs down while encouraging its owner to build it closer to their customers. Utilities can own projects under the proposed program.

The customers most likely won’t personally use the solar electricity in their contracts. Instead, they get credits for the energy they pay for, and that amount of electricity flows into the electric grid. The credits will only offset the generation cost that appears on each utility bill, so people will still have to pay other costs, such a transmission and distribution.

This rule is designed to address a criticism of an existing solar incentive program that allows homeowners to get retail pricing for the solar electricity produced by their rooftop systems and avoid paying corresponding transmission and distribution charges. Utilities have maintained that they should continue to collect these costs because they still have to maintain the grid at all time to send electricity to people’s homes at night or whenever their solar electric systems aren’t producing energy.

The idea of buying solar electricity without worrying about the equipment’s cost and location already has spawned novel business plans. Turning to crowd-funding to pay for solar installations is one such model. In some cases, you can pay to become one of the investors of a solar power project and receive a return on the investment over time.

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The nearly $1.9 billion project erected giant towers and built both above ground and underground cables that now run over 110 miles from Imperial Valley to San Diego’s territory. The project required 28,000 flight hours from helicopters to complete nearly 75 percent of the towers along the way (see video). The project uses both 500-kilovolt and 230-kilovolt lines, and it will initially be able to carry up to 800 MW of electricity (eventually the transmission rate should hit 1,000 MW).

San Diego Gas & Electric plans to use the Sunrise Powerlink to transport wind and solar power, such as the eight projects totaling more than 1,000 MW that are set to rise in Imperial County, the company said.

The project was a hard-won victory for the utility, which faced critics who were worried about the project’s environmental impact and skeptical that the project would really be used to move renewable energy and not mostly electricity from fossil fuel power plants. Other similar transmission line projects have been tabled and cancelled because of such concerns.

The California Public Utilities Commission approved the project in December 2008 after rejecting a proposal from an administrative law judge to deny the project. The judge argued that the utility didn’t need the transmission line, which would cause significant environmental damage, to meet the state’s renewable energy mandate then. The commission also decided against a proposal from one of its own commissioners that would’ve required San Diego Gas & Electric to put in writing that it would use Sunrise mostly for moving renewable energy.

Clean power highways

Building new transmission lines, or upgrading existing ones, has come to be viewed as a necessity as more power plants are proposed and set to rise from remote regions where there is space to accommodate large-scale projects that could produce renewable energy more cheaply than smaller ones. For California, which has an aggressive goal of getting 33 percent of its electricity from renewable sources by 2020, many of the solar farms are materializing in the eastern part of the state, in arid deserts and on former farmland.

Utilities are largely turning to these large power projects to help them meet the state mandate. But the cost of building transmission lines – and the risks involved if the lines are knocked off line by stormy weather or other natural disasters – also has promoted the idea of building solar projects closer to where the electricity will be used.

The utilities commission approved a program in 2010 to require the state’s three largest utilities to hold auctions to buy renewable energy from projects no more than 20 MW in size.  But 20MW still requires a big parcel of land, and some renewable energy proponents would like to see more solar equipment installed on commercial and residential rooftops instead. Those projects are more often kilowatt size.

Meanwhile, transmission line developers are looking at using newer technology to build projects that can carry a larger amount of renewable energy and do it more efficiently over long distances. China, which is building a lot of wind and solar farms, is where some of the world’s largest transmission projects are being built.

Photos courtesy of San Diego Gas & Electric

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While we’ve looked into many of the questions that last month’s proposed ruling from the California Public Utility Commission has raised, in my weekly update at GigaOm Pro (subscription required), I lay out some of the key points of contention suggested in the recent comments from smart grid industry players.

Chief among them is the fear that some of the CPUC’s definitions lack clarity, and that this vagueness could cause uncertainty and a delay in rolling out products and services to link homeowners and business owners to their energy use. The CPUC’s definition of “locked” versus un-”locked” home energy management devices is particularly troubling for the commenters. In fact, the the Consumer Electronics Association believes the distinction “threatens to dictate technology standards through regulatory favoritism.”

Other disagreements include a dispute over standards for connecting smart meters to in-home devices using wireless technology. The CPUC’s rules demand that California’s big three utilities make plans for piloting such meter-to-home connections within six months, but the rules don’t address how they’re supposed to do it.

The question around standards, in turn, brings up the question of whether it’s better to use the existing ZigBee standard, or wait for the next-generation of the ZigBee standard, which will be compliant with Internet protocol and able to be used via Wi-Fi and HomePlug devices as well as ZigBee. Pacific Gas & Electric wants to wait for the next-gen ZigBee standard to be developed, but that could take more than a year, given the current struggles over the standard.

The Demand Response and Smart Grid Coalition trade group, on the other hand, wants the CPUC to demand that it happens now. That’s not surprising, perhaps, given that its members include companies like Comverge, Tendril, Control4 and others using the first generation of the ZigBee standard in deployments today, not to mention the ZigBee Alliance itself.

Finally, amid all these confusions, it may seem that defining just who a utility “customer” is should be pretty simple, but that’s not always the case. For example, the Center for Democracy and Technology and the Electronic Frontier Foundation pointed out in their comments that the CPUC’s rules could leave residential and commercial tenants in an unclear position. Tenants might not be paying the bills and also might not be due the same protections and disclosures when it comes to their energy usage data.

Image courtesy of Portland General Electric via Creative Commons license

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While it’s too early to say just how state regulators will balance PG&E’s concerns with those of its anti-smart meter customers, I’m guessing meter opponents will focus in on the costs PG&E wants to charge customers — an up-front fee of $270 and monthly fees of $14, or up-front charges of $135 and monthly fees of $20, for customers not on low-income assistance plans.

Stay tuned for charges of “outrageous” fees from advocates, and responses from PG&E that it needs to charge extra for opt-out customers, both to hire meter readers and customer service personnel to support them and to install extra equipment to keep its smart meter mesh networks intact. The California Public Utilities Commission order that led to PG&E’s proposal does allow the utility to include “reasonable” fees to opt-out customers, but just what “reasonable” means is open to debate.

In the meantime, there are a lot of questions raised by PG&E’s proposal, both for its own smart meter plans and for others around the country. Here are three areas I’m going to be keeping an eye on in the weeks to come:

How will PG&E’s decision affect other smart meter rollouts? It’s no secret that some utility customers aren’t happy with their smart meters, but they’re unhappy for many different reasons. PG&E has been the target of just about every anti-smart meter argument there is, but its opt-out plan came in response to a very specific complaint — that the wireless radios within them create radio frequencies that can cause health risks.

Many scientific studies on this topic have been done, and they appear to reach the same conclusion — that smart meters broadcasting intermittently at the power levels and frequencies common for smart meter networks around the country present a much smaller exposure to RF than many other devices, such as cellphones and wireless routers, considered safe by the Federal Communication Commission.

Those studies haven’t changed the minds of people who fear that smart meters are making them sick, however — and PG&E isn’t the only utility facing an anti-RF crowd. Central Maine Power, for example, has faced a backlash against its smart meter rollout from customers worried about RF health effects, and some of them have filed a complaint with Maine Public Utilities Commission asking for an option besides wireless meters.

How will PG&E balance opt-out plans with giving customers the full benefit of smart meter technology? This is a tricky subject for the utility, because it opens up another line of complaint about smart meters — that they’re not delivering customer benefits to make up for the costs they’re charging customers to install them.

PG&E has already faced customer complaints that new smart meters have overcharged them for power. An investigation last year concluded that the smart meter technology worked, but that PG&E failed to fully use it to respond to customer complaints or reach out to explain the benefits of the new meters.

But how can PG&E deliver those customer-benefitting technologies to smart meters that don’t have their main communications channel turned on? Beyond serving as a “digital cash register” for the utility, smart meters are supposed to help detect power outages for faster renewal of service, allow for connections and disconnections that save truck rolls and operations costs, and other benefits meant to lead to lower customer bills in the long run.

If only a handful of people opt out of having their smart meters turned on, utilities should still be able to get those cost-savings functions out of the many smart meters that remain, of course. But there’s another, longer-range smart meter capability that will be harder to deliver to opt-out customers — home area networks.

PG&E is installing ZigBee radios in its smart meters, and eventually wants to connect them to in-home energy sensing and controlling devices to help homeowners measure and manage their energy use. Meters with their mesh radios disabled should still be able to beam their energy readings into homes — but will customers opposed to 900-megahertz mesh radios be OK with 2.4-gigahertz ZigBee signals coming into their homes? I’d guess not.

The question is, does PG&E have an obligation to find another way to connect those opt-out customers to their meter data? The Environmental Defense Fund believes so. UPDATE: EDF has spoken out in support of smart meters in general, and in the matter of PG&E’s opt-out plan, it released a statement that urged customers not to choose to have their meters’ radios turned off, noting that it could “prevent customers from seeing and taking full advantage of real-time usage and pricing information” — just the functions that meter-to-home connectivity are meant to provide.

At the same time, EDF has called for the utility to “ensure that the alternative option retains the full functionality of its smart meter and gives consumers a way to control their energy use and costs.” That’s going to be hard for the utility to do without a radio-enabled smart meter, however. There are ways to connect homeowners to their energy use besides smart meters, of course — they could install in-home energy sensing devices like Energy Inc.’s The Energy Detective, for instance. But those systems cost several hundreds dollars a pop — a lot more expensive than a simple meter-ZigBee radio connection. Should the utility have to subsidize those systems for opt-out customers?

Image courtesy of Velorutione via Creative Commons license.

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PG&E’s “radio-off” plan was released Thursday, two weeks to the day after the California Public Utilities Commission President Michael Peevey told the utility it had to present an option for customers who didn’t want a wireless-enabled smart meter attached to their home. A tiny, but very vocal, group of PG&E customers has been blocking smart meter installation trucks and successfully lobbying local governments throughout Northern California to place a moratorium on installing the smart meters.

Their complaint — that the 900-megahertz, wireless mesh radios built by Silver Spring Networks and installed in meters made by Landis+Gyr and General Electric can cause human health risks — is not supported by the weight of scientific evidence. Even so, communities across PG&E’s service territory have imposed a moratorium on installing the meters, although such moves by city and county governments don’t carry legal force.

PG&E’s plan calls for customers to pay “reasonable upfront and recurring fees to cover the costs of turning off the radio, manually reading the meters every month, modifying IT systems and providing information to customers on the program through call centers and other channels.”

UPDATE: PG&E wants to charge an up-front fee of $270 and monthly fees of $14 for regular customers who choose the opt-out option, or $215 up-front and $11 per month for members of its CARE program for low-income customers, but it’s also offering different plans that bring down the up-front costs to as low as $105 in exchange for higher monthly payments. PG&E needs to charge more, not only to pay meter readers and customer care reps to manage those opt-out customers, but also to strengthen the wireless network to make up for the missing radios — an important consideration in mesh networks that “bounce” signals from one meter to another to increase coverage area.

It also allows for a separate tariff for customers who want the meter moved to a different location on their property: an option that appears to be designed to cater to customers who believe the radio signals being generated by the meters, which carry less strength than cellphones, are threatening their health.

Just how the new plan might affect the costs of PG&E’s $2.2 billion, 10-million smart meter rollout remains to be seen. PG&E has already installed about 8 million of the new meters, making a wholesale change in the architecture of reading the meters a very expensive proposition.

PG&E’s new plan doesn’t include any mention of using hardwired connections for smart meters, by the way. Companies including Echelon and Aclara provide technology to send data over the same power lines that carry electricity to smart meters, for example. While most smart meters being deployed in the U.S. today use wireless technologies similar to the RF mesh provided by Silver Spring, U.S. utility Duke Energy is using Echelon’s meters, which are also getting lots of traction in Europe. Other technologies to carry smart meter data over phone lines exist, though they’re more than a decade old and not in regular production today.

The new plan also doesn’t get into how opt-out, radio-off customers might be able to avail themselves of having their smart meters connected to in-home energy networks to link them with utility pricing programs. PG&E has decided it will use ZigBee wireless communications to link smart meters to home area networks, but hasn’t yet turned on any of these capabilities. Without a communications path to the utility, it’s unlikely that opt-out customers would be able to be turned on once PG&E decides to start connecting those HAN-meter gateways.

The CPUC has yet to review PG&E’s new plan. The anti-wireless protests aren’t the only problem the utility has run into with its smart meter project. Customers in Bakersfield, Calif. started the outcry in 2009 by accusing the new smart meter of overcharging them for their power, and a lawsuit is in the works. A Sept. 2010 report on PG&E’s smart meter program found the system wasn’t overcharging customers, but the utility had made mistakes both in implementing the new technology and in reaching out to customers to explain how it would change their bills.

Image courtesy of Tom Raftery via Creative Commons license.

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The governor signed a bill that’s notable, because it’s apparently the first legislation in the country to look at how energy storage might be necessary for meeting a state’s goals to increase its use of renewable electricity. California has set a high standard by planning to get 20 percent of its electricity from renewable sources by 2010 and 33 percent by 2020. The state won’t be meeting its 2010 goal, but the law gives utilities a few years’ grace period to fulfill the 20 percent mandate. Energy storage isn’t the reason why the 2010 goal won’t be met by the end of this year; the difficulties of developing and financing renewable energy projects – and the time it takes to get regulatory permits – are key factors.

The new law (PDF) is a watered-down version of an initial effort to require the state’s investor-owned utilities to invest in energy storage. Instead, the law requires the California Public Utilities Commission to start the process of determining whether energy storage is necessary for the investor-owned utilities by March 1, 2012. The CPUC has until Oct. 1, 2013 to adopt an energy storage procurement target if it deems storage necessary. If that happens, utilities will have until the end of Dec. 2015 to meet the first target, and the end of 2020 for the second target. Municipal utilities and public utility districts, which aren’t regulated by the CPUC, also have to follow similar deadlines.

Utilities and local governments don’t like mandates, particularly ones that might cost them a lot of money and may not be considered necessary in the first place. Storage can serve several purposes, including providing a steady amount of power to the grid over hours when consumer demand is high, as well as sending short bursts of power for keeping the grid working at a particular frequency. Installing storage farms can reduce the need to build more fossil-fuel power plants, presumably because the storage farms use more eco-friendly materials and have a lower carbon footprint.

Given the growing amount of solar and wind energy coming online — and that their generation doesn’t happen steadily around the clock — banking it makes sense. There’s an argument that the grid is too old and inadequate to accommodate this new flow of renewable energy, but that belief is up for debate. “We have a robust grid today that can accommodate thousands of megawatts of variable generation,” said Julie Blunden, SunPower’s executive VP of public policy, in a previous interview to discuss a California grant SunPower had won to test energy storage technologies for businesses that have solar panels on their rooftops.

Banking renewable energy for use when electric rates are high does make economic sense. Electric rates are high during peak demands, such as early afternoon when it’s hot, or early evening when people return home and turn on lights, TV and appliances. Solar energy is produced during the day, so its production more closely follows the power demand, particularly in western states. Wind farms tend to be more productive at night, so many energy storage demonstration projects are looking at conserving wind energy and using it during the day.

Then, there are the issues of technology choices and costs. The federal government has doled out hundreds of millions of dollars to technology developers to come up with good batteries, fly-wheels and other methods of storing and discharging energy. A123 Systems and Beacon Power are among the beneficiaries of the government largess. Utilities and storage system developers, from Pacific Gas and Electric to AES Energy Storage, have received hundreds of millions more to engineer and build storage farms using some of these more cutting-edge technologies, but these new technologies aren’t cheap.

California’s new storage law doesn’t list the technologies that utilities might be required to use. The cheaper storage technologies now are pumped hydro and compressed air, two older technologies. In fact, PG&E filed an application with the CPUC in August to study the feasibility of building a 400-megawatt to 1,200-megawatt pumped hydro storage system — which would pump water to a reservoir at a higher elevation so it could be released to generate electricity as needed — on the Mokelumne River in eastern California.

PG&E won a $25 million grant from the federal government to do a feasibility study on a 300-megawatt compressed air storage project in Kern County. Compressed air storage involves using an underground reservoir to store the compressed air (pumped into storage when extra energy is produced, mostly in non-peak hours) before releasing it to produce electricity during peak hours.

The energy storage law doesn’t say utilities have to install their own energy storage systems or buy services from owners of large storage farms. That means, potentially, that businesses that install storage systems along with solar panels on the rooftop can sell their banked solar electricity to utilities and get paid for it. It also means that solar installers that own and operate solar arrays and sell the electricity to its customers could end up in the energy storage service business and compete with pure-play storage service providers.

A lot of good business opportunities certainly could exist thanks to the new law. But whether there will be a mandate and what that mandate might say will certainly invite heavy lobbying and big debates, the same kinds of battles the state has gone through to set and meet its renewable energy mandates.

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Image courtesy of Argonne National Laboratory.

Thursday’s report, unveiled at a California Public Utilities Commission meeting in San Francisco, closely matched one that PG&E itself delivered in May. As Stacey Wood with Structure Group put it, “We found no systemic issues beyond the specific issues already reported by PG&E.” In fact, out of the 1,378 smart meters tested, all proved reliable at levels “consistent with industry standards” and provided “accurate meter data flow to billing,” she said.

That means that the price increases customers blamed on smart meters are due to other factors, Wood said, including a heat wave that boosted air conditioning use and rate increases over last summer that “were amplified because of the impacts of weather.” In fact, given that some 5 percent of the older mechanical meters being replaced weren’t working properly, it’s possible that customers seeing higher bills after smart meter were installed may have actually been getting under-billed before, she noted.

But PG&E did incorrectly apply new rates in a few cases, and some customers on a low-income rate reduction program saw billing inaccuracies, Wood added. Those problems tied into a general lack of customer support and complaint management on the smart meter front, Wood said. PG&E “provided little communication on the new meters,” and once complaints started to come in, PG&E “did not utilize new information such as interim measurements” from the new smart meters, which could have helped answer customer questions, she said.

Compared to a set of industry best practices, the report discovered “several items of partial or non-compliance, particularly in the areas of complaint troubleshooting and account billing.” That included a too-high tolerance for billing mistakes to be passed out of the system, she said — bills were at first only being checked if they exceeded $1,700, before that trigger was shifted down to a more reasonable $300, she said.

That’s when smart meters were actually being used for billing, she noted — but because PG&E was installing meters faster than it could start using them, manual meter reading continued for an average of 131 days after a new smart meter was installed before it was “utilized from a billing perspective,” she said.

Several CPUC commissioners said they welcomed the validation of PG&E’s smart meter technology, but wanted to see improvement on the customer service side. As Commissioner Dian Grueneich said, “We need to see a rapid response from senior management at PG&E that gives some assurance the utility will be coming to the top of the class on these best management practices.”

CPUC President Michael Peevey singled out PG&E in Thursday’s meeting, saying that it accounted for the vast majority of complaints to the CPUC about smart meters in the state. By comparison, deployments at San Diego Gas & Electric and Southern California Edison have yielded almost no complaints, he said.

PG&E’s smart meter rollout also included a major mid-stream shift in technology. While the utility began by deploying electricity meters from Aclara, it later found that up to 5 percent of those meters were performing below expected. PG&E switched to new smart meters made by General Electric and Landis+Gyr and embedded with networking gear from startup Silver Spring Networks — and those meters, Structure’s report found, have been performing within industry guidelines.

PG&E has also beefed up its customer relations to include a dedicated smart meter hotline and walk-in centers in Oakland, Fresno and Bakersfield, the latter city home to customers at the center of the class-action lawsuit against it. Just how Thursday’s report will affect that lawsuit remains to be seen. A Texas state judge ruled earlier this month that a similar customer lawsuit against utility Oncor should be handled by the state’s PUC, rather than in the court system. A PG&E spokesman told me Monday that a California state court judge was awaiting clarity from Thursday’s report before making any potentially similar rulings in PG&E’s case. Whether the court will more heavily weight PG&E’s clean bill of health on smart meter technology, or the findings of less-than-stellar account and customer management, is an open question.

It’s also too soon for Thursday’s report to determine how the CPUC will respond to requests to halt PG&E’s smart meter deployment, commissioner Nancy Ryan said. San Francisco City Attorney Daniel Herrera had asked CPUC for a moratorium on smart meter installation until the release of Thursday’s report addressed overcharging concerns. Utilities in Maryland and Hawaii have seen their smart meter deployment rejected on the grounds that they rely too much on raising customer rates.

Thursday’s CPUC meeting did draw people protesting against smart meters, but not on concerns of overcharging. Rather, a dozen or so people claimed that the electromagnetic radiation being put out by the smart meters has been making them sick, and others cited studies claiming a link between electromagnetic radiation and health risks including cancer.

Fairfax, Calif. officials have cited these health concerns in demanding that PG&E not install smart meters in the city. PG&E contends that smart meters are far less powerful than cellphones and other radio devices. In any case, the Federal Communications Commission has collected a wide array of studies on the health effects from electromagnetic radiation to give guidelines that PG&E must follow in deploying radios in smart meters in neighborhoods, and Peevey said CPUC would defer to the FCC on that matter.

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Image courtesy of Kevin.