NEW YORK (The Deal) -- British billionaire Richard Branson struck a monumental partnership with NRG Energy (NRG - Get Report) last year to shift his 74-acre Necker Island to 75% renewable energy by the end of 2015.
Retail electricity prices on small Caribbean islands are expensive because they rely on imported oil to power generators. While the recent plunge in oil prices has provided some relief, gas and electric prices on the islands are still exorbitantly high.
One of the primary reasons Branson was able to embark on this endeavor is because the cost of solar photovoltaic technology has come down exponentially. The average price of a completed PV system has dropped by 33% since the beginning of 2011, according to the Solar Energy Industries Association.
Despite having an estimated net worth of $4.9 billion, even Branson was not able to operate off the grid using 100% renewable energy. Dan Hagan, head of White & Case's energy markets and regulatory practice, says, "If Richard Branson isn't able to completely get off the grid using renewable energy, then it is probably safe to say that it won't be getting into middle America anytime soon."
The main reason Branson wasn't able to do so is because the cost of storing energy in batteries right now is prohibitively expensive and impractical.
However, the technology could advance to make storage more common and affordable well into the next decade or more, said Mihoko Manabe, a senior vice president at Moody's Investors Service. Scott Wiater, president of Rockville, Md.-based Standard Solar, believes it is "very realistic" that the technology will advance exponentially and he too said it will probably happen within the next 10 years.
Should that begin to happen, as experts believe it will, the effect on utilities-and consolidation in the industry-may be far-reaching indeed.
That's because if energy storage costs and technological advances continue to make it more advantageous for customers to disconnect from the grid, it would ultimately threaten the traditional utility model.
Some industry participants have even referred to this potential mass grid defection as the "death spiral" for utilities.
"In the future, customers won't need to be plugged into the grid anymore. The utilities that are smart and forward looking will try and own distributed generation assets. The ones who are slow will find themselves extinct like the dinosaurs," Wiater says.
Only large customers historically have been able to generate their own power, but now, it's feasible for smaller customers to do so as well, Manabe says.
"While solar overall accounts for less than 1% of electric generating capacity in the U.S., the double-digit increases in residential solar installations are pushing lawmakers and regulators to act sooner rather than later," Manabe says.
Residential installations grew 60% in 2013 and hit an annualized installation rate of over 1,000 megawatts in 2014, according to Fitch Ratings. The agency projects a 40% growth rate in residential installations in 2014, and it expects that rate to be approximately 30% in 2015 and 2016.
The name for it in the industry is "distributed generation," or DG, which is electricity that is produced at or near the point where it is used, as the Solar Energy Industries Association defines it. Distributed solar energy, the most common form of DG, can be located on rooftops or on the ground, and is typically connected to the local utility distribution grid.
"For electric utilities, no reprieve is in sight, even with the 30% expiration of the federal investment tax credit in 2016 [for solar energy projects], said Glen Grabelsky, a managing director at Fitch, during a presentation at the Edison Electric Institute Financial Conference in Dallas in mid-November. He said improved panel efficiency and lower installation costs would continue to drive solar PV sales.
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Manabe adds that the proliferation of solar companies like San Mateo, Calif.-based SolarCity (SCTY) that are providing attractive financing options for residential customers, are making rooftop solar much more affordable.
"What this ultimately means for utilities is that their customers will buy fewer kilowatt hours, and thus, utilities' revenues will decrease," says Suedeen Kelly, a partner and chair of Akin Gump Strauss Hauer & Feld's energy regulation, markets and enforcement practice. "If the market for utilities shrinks, we will see more M&A."
For example, there could be opportunities for utilities to acquire other utilities that have gotten caught in the so-called death spiral and need a rescue, Kelly says. She cites Atlanta-based Southern (SO - Get Report) , whose unregulated subsidiary Southern Power struck a partnership with Ted Turner's Turner Renewable Energy to pursue the development of U.S. renewable energy projects. The partnership has primarily focused on developing and investing in large-scale solar PV projects in the Southwest, where solar resources are most available.
Not everyone is in agreement that the utilities will go the way of the dinosaurs. Hagan, for one, views the death spiral as "overstated," though he agrees there is a potential for that happening if the regulatory framework isn't changed.
In addition, if utilities get into the business of selling solar systems to customers, that could bring pressure to bear on the solar companies, meaning the smaller, newer companies may turn to the utilities as potential partners-or for buyouts, Kelly says.
That's what someone like Wiater says he sees in his company's future: a partnership with a utility and then, eventually, an acquisition. Standard Solar, with under $100 million in revenues, has been owned by private equity firm Truecast Capital since 2008 and its owner "definitely" discusses the topic of an exit, but no time frame has been set, he says.
Even some of what looks like straightforward M&A in the industry may be rooted in DG. One industry participant says he thinks one of the reasons Florida-based NextEra Energy (NEE - Get Report) agreed to a $4.3 billion deal in December to acquire Hawaiian Electric Industries (HE - Get Report) was to gain an understanding of the DG market. "NextEra understands that rooftop solar is going to become increasingly important in Florida so Hawaiian Electric will be its test tube baby," he says.
There is certainly a federal overlay, but the vast majority of renewables development is driven by state policies, which vary, as some states are more pro-DG than others, says Hagan.
According to Moody's, the top 10 states favoring DG adoption include California, Hawaii, Connecticut, Oregon, Delaware, Arizona, Massachusetts, New York, New Jersey and Maryland.
While state policies are a critical component of DG adoption, Hagan says geography also plays a significant role, as certain regions, such as the Southwest, simply get more sunshine than others.
Another important factor affecting DG adoption is whether a state has high electricity prices, Manabe says, as is the case in Hawaii, where customer bills are the highest in the nation. As an island state, Hawaii faces a lot of the same issues as Branson does on his private domain-multiplied many times over.
The state regulatory response, which will probably include increasing rates to customers, will be critical in helping utilities keep their revenue streams, Kelly says. However, at some point, Hagan says the regulators might not allow these exorbitant rates to be passed on to the customers.
Every state is paying close attention to what is done in this area because DG does not work in the existing regulatory structure.
The problem is something called net metering. That's what allowed solar panel customers to lower their electric bills because any excess kilowatts the customer generates are subtracted from the number of kilowatts supplied by their utility when the monthly bill is calculated. That, of course, lowers the amount they pay to the utility-besides environmental concerns, it's one of the main reasons customers want to switch.
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But while one customer might enjoy the benefits of net metering, the cost is often passed on to those without DG options. "Net metering is negligible from a ratings perspective, but DG is lessening sales for utilities, which is a worrisome trend. The situation is likely to get worse as solar installations increase," said Robert Hornick, senior director at Fitch, at the EEI conference. "It's causing a dilemma for both the regulators and electric utilities."
Right now, net metering exists in 43 states and while it has been around for years as a way to promote renewables, utilities are now trying the change the incentives.
And no state has addressed these issues comprehensively, so other jurisdictions still don't have a benchmark to follow.
One approach has been to propose a fixed charge on all customers to make their revenues more predictable. In 2013, legislation was passed in California allowing for net metering changes and the implementation of a fixed charge of up to $10 per month beginning in 2017. In Maine, regulators increased fixed charges by $3 per month and in Connecticut, the utility Connecticut Light & Power, proposed a $9.50 per month uptick.
Another approach has been to impose a charge specifically on DG solar customers-an approach taken by Arizona, Hawaii, Oklahoma, Maine, Utah, Colorado and Wisconsin.
In Arizona, the issue became particularly contentious. The electric utility, Arizona Public Service, recommended a charge in the $8 per kilowatt range, but the regulator ultimately voted three to two in November to charge DG users a mere 70 cents.
A few states have been at the forefront of pursuing a new utility model embracing DG, including California, New York and Hawaii, Manabe says. While these plans differ, they all have the goal of moving from a model where power flows one way from the utility to its customers to a two-way model, which allows customers to have more power options, including standby service for rooftop solar, she said.
This could be an opportunity for transmission and distribution utilities, as they do not own generation, and therefore are not in competition with DG, unlike traditional vertically integrated utilities, which own their generating plants, Manabe says. T&D utilities are situated in jurisdictions where utilities divested generation assets during the electricity deregulation in the 1990s, she explained.
With DG, the customer typically has more than enough power and can send it back to the utility, but since the system wasn't designed to handle the back flow of power, changes to the grid must be made.
The grid then potentially becomes even more important, as the T&D grid will need substantial investments to accommodate the increase in DG, Manabe says.
However, overall, "It's the perfect storm for utilities because they are facing decreasing load growth, declining revenues, and yet costs are increasing," Hagan says. "When you take DG into account, it just exacerbates the problem."