At the Solar Power International conference in Dallas last week, a panel of utility executives served up some telling views about their interest and misgivings about investing in solar. Here is a takeaway of some of the key points:

1. Price is still a big barrier: There has been lots of talk about the rapid decline of solar panel prices and the rise of large-scale solar farms, but the price for solar hasn’t come down far enough, utility executives said. That means they aren’t likely to invest in it unless they have to in order to meet state mandates. The issue is particularly thorny in places of the country with super low electric rates (and lower numbers of sunny days). Robert Powers, president of AEP Utilities, noted that the average wholesale price for power in general in several northeastern states this summer was $0.04 per kilowatt-hour when the price for solar was around $0.20 per kilowatt-hour.

Larry Weis, general manager of Austin Energy, noted that wind energy development has continued to grow and at cheaper costs. “It’s difficult to say, OK, let’s go out and build 200 MW of solar now when can acquire 200 MW of wind for roughly half the cost,” he said.

2. Too much reliance on government help: The solar industry has largely depended on a 30 percent investment tax credit and other federal and state incentives to help them finance projects. While utilities can take advantage of the tax credit and other help if they want to invest in solar, they are leery of having to factor in government incentives when they do long-term planning for power plant construction.

“State and federal support will go away, and we have pressures from our owners they don’t want us to rely on the (investment tax credit) forever. They don’t like earnings that are based on taxes,” said Randy Mehrberg, Chief Operating Officer of PSEG Energy Holdings in New Jersey. “Cost, at the end of the day, is what haunts all of us.”

3. Money and technology: Although the government has invested billions of dollars into renewable energy, it’s facing high pressures to limit spending. “One thing we don’t talk about enough in the energy industry is capital as a resource,” Powers said. “There is a finite capital to solve the U.S. and the world’s climate issues. Policy makers will face the inevitable question: if I spend a dollar on solar, a dollar on natural gas, or a dollar on wind, how do I solve some of the broader policy issues because I’ll eventually run out of the capital if I don’t spend my dollars efficiently.”

Powers said one way to make solar attractive is to pair it with energy storage, which can bank solar and deliver power to utilities who need it to balance their supply and demand and to make sure any sudden flow of renewable energy (when the wind starts to blow or the sun comes out from behind the clouds) doesn’t disrupt the grid’s operation.

Doyle Beneby, CEO of CPS Energy, a municipal utility in San Antonio, said the use of demand-response technology can help turn solar into a more predicable source of energy sooner than storage can. The utility plans to build a communication network for 150,000 of its customers by 2015 that will allow it to reduce power use of households. “Our view is that on days when the cloud covers come in and your solar output dips, we can have volunteers have their power turned down,” Beneby said. “We can get that to market before battery technology is scalable enough to have an impact.”

4. Some policies are desirable: Utilities don’t like to be told they have to invest in more expensive energy or technologies. But if their consumers start to demand cleaner power or if there is one day a price on carbon emissions – and some utility executives think eventually there will be – then utilities want to make sure they can pay for all the costs. One way to do that is to support renewable energy mandates, which typically come with mechanisms for utilities to recover part of the extra expenses by passing on costs to ratepayers.

Armando Olivera, CEO of Florida Power & Light, said a big disagreement between proponents of centralized and distributed solar generation has made it difficult to lobby the Florida state legislature to pass a clean energy mandate. The company wants to do large-scale projects because they are cheaper. The retail electric rates in Florida are about 27-30 percent lower than national average, so the utility wants to do solar as cheaply as possible to minimize rate hikes, Olivera said. The company has built 3 solar projects totaling 110 MW in the last few years. “We think we can do the same projects at 30-40 percent cheaper now than we did three or four years ago. We have another 500 MW we can start construction if we have the right policy,” Olivera said.

5. Idealism and reality: Solar energy advocates have been touting many polls showing that Americans want clean energy, and utility executives largely agree. But they don’t always want to pay for it. Armando Olivera, CEO of Florida Power & Light, said its residential customers have expressed a willingness to tag on another $3 per on their bills to support solar. Randy Mehrberg, chief operating officer of PSEG Energy Holdings in New Jersey, offered up this anecdote:

“We ask our customers regularly what they would like to see from us. So we asked them, what is the No. 1 we can do for you besides lowering your bill? The No. two answer was more renewables. Guess what the No. 1 answer was? The answer was ‘Lowering the cost of our bills.’”

Photo courtesy of BFS Man via Flickr

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I was just wondering what had happened to all the plans for so-called carbon capture and sequestration (CCS) projects, a technology which has long been deemed crucial to reach carbon emission reduction goals by scientists, but also a technology that has so far failed to reach commercial scale because of its very high cost. The idea behind the tech is to capture the carbon emissions at a coal plant, store that carbon somewhere, like deep underground, and enable coal plants to produce electricity without much of the dirty carbon emissions.

Two years ago, the Department of Energy pledged hundreds of millions of dollars in funds from the stimulus package for AEP to “design, construct and operate a chilled ammonia process”  at the coal plant. AEP planned to eventually, over a ten year construction process, pipe the captured and compressed CO2 over to two saline formations 1.5 miles underground. The total project was supposed to cost $668 million, reports the New York Times.

The move to cancel the plan shows just how far back the weak economy, and the changed political climate has pushed back capital intensive green technologies. AEP tells the New York Times that it didn’t think state regulators would approve rate hikes for customers to pay for the project. Adding the CCS technology can raise the price of the coal power by 50 percent, and the tech only becomes economical when the price of carbon reaches levels around $100 per ton.

AEP is the largest producer of coal-fired power in the U.S. and back in October 2009, AEP’s CEO Michael Morris called starting the process of capturing the carbon emissions from the plant: “the beginning of a technological road map.” The project was one of the largest in the U.S. Now it appears to be a dead-end. Now who’s taking bets on FutureGen?

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AEP Ohio is planning to put some 80 refrigerator-sized battery units in the field to figure out just how customers will be able to use this kind of local backup power — and what they might be willing to pay for it. Over at my weekly update at GigaOm Pro (subscription required), I get into some of the variables that AEP and its business partners will be testing in the months and years to come to see if so-called community energy storage (CES) will be worth the investment.

AEP’s community energy storage project, funded by a $75 million grant from the Department of Energy, is among the first to test out ways that distributed batteries might be able to make energy storage economic at the household level. It isn’t the first kind of battery AEP has tried out — the utility was among the first in the country to try out massive, high-temperature sodium sulfur batteries to back up stressed-out sections of its grid.

But sodium sulfur batteries are the size of cargo containers and need to run at nearly 1,000 degrees Fahrenheit, which makes them unfriendly neighbors. Not only that, but they’re blunt instruments — they can balance a neighborhood feeder line as a whole, but not individual houses or offices on that feeder line.

AEP’s first test battery in this project, on the other hand, is now hooked up to the home of an AEP employee, Terri Flora, corporate communications director for AEP Ohio, told me in an interview last week. Chicago-based S&C Electric is installing, networking and controlling the 25-kilowatt lithium ion batteries, which are being built by Allentown, Pa.-based International Battery.

Three more adjacent homes will be connected later this month, she said, and eventually, the utility envisions putting 80 battery units, each about the size of a refrigerator, in backyards to back up three to four homes each. From there, AEP will be testing a variety of functions, starting with basic reliability assistance, she said.

First on the agenda is helping homes ride through power outages for an hour or two. That’s primarily a benefit to customers, though it could save the utility some money by letting it more efficiently prioritize outage repairs. The point is, AEP wants to concentrate on customers benefits right off the bat — prudent, perhaps, considering the customer backlashes we’ve seen to other smart grid projects that didn’t provide up-front customer benefits.

But once you’ve hooked up houses to ride through outages, why not use the same capability to power them through peak loads, shifting their full grid burden by an hour or two to help the utility ride through peak demand times? AEP is looking at that too, Flora said.

Further down the line, AEP wants the batteries to provide voltage and frequency stability to ease wear and tear on transformers and power lines — exactly the kind of distribution grid management S&C specializes in.

Beyond that, linking batteries to customers could allow them to buy power backup services or store power to use when prices spike, Flora noted. Those ideas are still on the drawing board — but given that Gehenna’s residents are also getting some of the 110,000 smart meters from Silver Spring Networks that AEP is deploying in the central Ohio region, connecting homes to batteries might be in the future, she said.

Come hear more about energy storage and the power grid at our Green:Net 2011 event on April 21, in San Francisco.

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Image courtesy of Reallyboring via Creative Commons license.

We’ve been tracking Texas’s distinctive smart meter landscape for some time, including its status as a fully deregulated market. That means big transmission and distribution utilities like Oncor, CenterPoint and AEP have to open their end customers to dozens of retail electricity providers (REPs) like TXU. That also makes the state’s power market a lot more like consumer cable or broadband markets, where companies can compete on products and services.

As I explain in my article for GigaOM Pro (subscription required), perhaps that’s why Texas’s legislature has decided to force its utilities and regulators to push out smart meters. The Texas Legislature passed a law in 2005 giving the Public Utility Commission of Texas a mandate to move forward with smart metering projects, as well as leeway to allow utilities to pass on surcharges to customers to recover the costs of doing so.

That, in turn, has allowed the PUCT to allow utilities to pass on some pretty hefty customer cost increases to pay for smart meters. Texas utility Oncor is charging $2.21 per customer per month, a rate increase that included set-asides for customer education and aiding low-income customers, PUCT Chairman Barry Smitherman said in a smart metering conference call last week. Smaller Texas utility CenterPoint was able to charge $3.24 per month increases for the first two years and $3.05 thereafter.

By comparison, California’s Pacific Gas & Electric — the utility leading the country with some 6.4 million smart meters deployed so far — sought average monthly increases of only 49 cents to 99 cents per customer, and Chicago utility Commonwealth Edison is asking customers to pay just $5 more per year, or about 42 cents per month.

Texas is also leading the way in collecting and presenting its smart meter data to customers. Its Smart Meter Texas Portal went live earlier this year, and allows customers to access information on power usage, billing and pricing, as fast as today’s technology can deliver it. It also opens that information to REPs and other designated third parties — perhaps one reason why Google, which is developing third-party home energy management platform PowerMeter, has pointed to Texas as a model it would like California and other states to emulate in connecting customers to smart meter energy data.

Texas also seems to have weathered the consumer backlash against smart meters pretty well so far. A lawsuit accusing Oncor’s smart meters of jacking up customer bills has been sent back to the PUCT’s more friendly jurisdiction, and a study by Navigant Consulting (pdf) reported this summer that smart meters in Texas are working properly. In this supportive environment, even Texas utilities not subject to deregulation — municipal utilities such as Austin Energy, or cooperatives like Bluebonnet Electric Cooperative — are moving forward with smart meters.

Still, as a recent study by consultancy KEMA noted, Texas customers are like their brethren around the country in that they don’t particularly care about managing their energy use and don’t want to pay more for power. All of the state’s cutting-edge smart meter deployments and customer communications efforts will have to fight those trends if more advanced home energy management, demand response and other next-generation smart meter applications are to take root.

To read my full report, and my daily news articles and story links, check out GigaOM Pro’s Green IT section.

Image courtesy of Tim Patterson.

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