Is on-bill financing better than PACE?

Could Be a Boon for US Smart Grid Firms

Katherine Tweed: February 22, 2012

In terms of smart grid trends, the United Kingdom ranks high in the areas of raw excitement for vendors. With a goal of installing 47 million meters by 2020, and an open bid for $7.5 billion in communications contracts, companies large and small are looking to be a part of what’s happening in the U.K.

Starting in October 2012, there is one more area that should get a lot of attention: Green Deal. The program, which is run by the government but privately financed, will help homeowners and businesses with energy efficiency improvements up to £10,000 ($16,500) with no upfront costs.

“Green Deal, in a nutshell, is a framework that enables firms to offer consumers the opportunity to invest at no upfront cost and attach the charge to their utility bill,” explained Dan Monzani, deputy director of Green Deal legislation and finance at the U.K.’s Department of Energy and Climate Change (DECC), which is overseeing the program.

If it sounds a little like PACE financing, Monzani is quick to point out that it is actually quite different. Instead of being tied to the mortgage, the financing is tied to the utility bill on the property. Some of the most vociferous opponents of PACE programs in the U.S. were mortgage lenders, who are totally out of the picture in the Green Deal scheme.

If a homeowner, for example, wants to receive money for an upgrade, he or she must contact someone who is approved by the program to do an impartial assessment. From there, the homeowner can use an accredited, approved contractor to the work. If the person moves, the financing stays tied to the utility bill at the house, and the new homeowner is aware before the purchase of the Green Deal fee attached to the bill.

The types of retrofits eligible for the program will include upgrades that will stay with the building, improve the energy efficiency and pay for themselves in a reasonable amount of time. For homes, much of the money will likely go to insulation upgrades. It also means that energy-efficient smart appliances, which could be ripped out when someone moves, will not be part of the Green Deal.

On the back end of the deal, utilities will be collecting money, but they are not the lenders. The utilities will receive a small portion as an administration charge for running the billing program. The money is coming from a consortium of banks that are putting up the money, a total of $21.5 billion in the next decade, with the assumption that they will receive a steady payback through the Green Deal. The investments will likely be packaged and sold to retirement funds.

Insulation will be one focus for homes, but there are a variety of other energy efficiency upgrades that will be included in the program. Monzani noted that something like window glazing, which offers some increase in efficiency, but is also done for aesthetic reasons, would be partially -- but not totally -- covered by the Green Deal. “If you can demonstrate your product saves money on the typical energy bill,” said Monzani, “you can be in the Green Deal.”

He also hinted that smart buildings controls, if they could be proven to save enough energy, would also qualify. “It’s very much designed to work around the whole-house retrofit,” said Monzani. He expects that contractors will be offering products covered by the Green Deal, and also others that may improve convenience or efficiency, even if they’re not part of the deal, when they are working with customers. After all, insulation isn’t very sexy, even if it saves money, but getting some cool new smart thermostats might seem like a good buy if the insulation is already free.

Having energy efficiency assessors and contractors in millions of homes could be a boon for home energy management companies such as Onzo, Tendril, Trilliant, EnergyHub, AlertMe and others that are competing, or looking to compete, in the U.K. market.

But it’s not just for folks on the home front. “We think the small business sector will be a big winner,” Monzani said of the Green Deal. From small stores to hotel chains, there will also be upgrades available for the commercial sector.

The Green Deal is a separate initiative from other energy-focused programs initiated by the U.K. government, such as smart metering and feed-in tariffs. Instead of tying them all together, the government will let the private sector find ways to bundle the offerings in ways that work for customers.

For private companies that want to serve the market, partnering will be key. Some firms like Trilliant are already thinking that way by forming alliances that can leverage each partner firm's platform.

Although the utilities don’t seem like winners in the Green Deal, Monzani said many were very supportive of the program. British Gas expects to see more money from energy services than energy delivery by 2020, so the Green Deal is a perfect project to pitch in order to frame the organization as much more than just a utility delivering gas and electrons.

Many other European countries and U.S. regulators are watching the Green Deal to see if it could be tweaked for their own markets. In the U.S., on-bill financing is already catching on as a means to allow commercial customers to undertake energy efficiency upgrades, and California is considering on-bill financing for residential retrofits.

Currently, the U.K. government is seeing a lot of companies interested in Green Deal and it’s finalizing the list of eligible upgrades that will make the cut to be included in the program. For now, the DECC is just ironing out the wrinkles to make sure it’s a seamless launch in October. “It’s a complex scheme,” he said, noting that it took a lot of work to make sure the interaction between the government, banks and utilities is smooth. “We know it’s complex in its back wiring, so that it can be simple for the consumer on the front end.”

Will Italy's FiTs Survive the Fall of Berlusconi?

By Rachana Raizada February 21, 2012

Milan, Italy -- Never one to do anything by half-measures, a somewhat surprising legacy of ex-Prime Minister Silvio Berlusconi's government has been to send installed capacity in Italy's photovoltaic (PV) market soaring through the roof. Reacting to a resounding public vote against nuclear power in 2011, a fourth edition of feed-in-tariffs (FiTs) was announced for the sector and though somewhat reduced, they were still high enough to keep Italy's "PV counter" ticking faster than ever.

According to Gestore dei Servizi Energetici (GSE), the agency which supports the development of renewable energy on behalf of the Italian treasury, Italy had reached 10 GW of PV capacity by September, a calculation based on applications for incentives. By January 3, 2012 this figure ballooned to 12.5 GW at a cumulative annual cost of €5.4 billion and over 319,000 installations.

However, a recent report published by KPMG Advisory in Italy, which documents the remarkable growth of Italy’s renewable energy market, is emphatic that while these technologies present an attractive solution for a secure energy supply with reduced import dependence, the incentive mechanisms which have been so instrumental to sector growth are unsustainable.

In late November 2011, Investing in Renewables: Trends, Opportunities and Perspectives was first presented to an audience of around 50 key sector players. According to Gianpaolo Attanasio, the associate partner responsible for the report, the audience had two major concerns: stability of regulations for the future and fear that a sharp reduction in future subsidisation of the sector could halt investment activity and lead to delocalisation to the neighbouring countries of Eastern Europe. Indeed, with an unexpectedly new "technocratic" government in place, a scheduled talk by the representative of the Ministry of Economic Development was cancelled. "The concerns are not about the evolution of the regulation itself," says Attanasio, "but about the mid-term stability of this regulation. The big concern in the past was that every 12 months the regulation kept changing."

As described by Attanasio, the report was driven by two motivations: to define quantitative scenarios for green certificates for the wind, biomass and mini-hydro sectors based on realistic assumptions, and to paint a complete picture of Italy’s renewable energy landscape for potential investors. The comprehensive report summarises the history of incentives for the sector; benchmarks some of the key players, and touches on more specific issues such as reaching grid parity, project financing and M&A activity.

Italian attitudes towards renewable energy are not politically polarised, and it is generally seen as an attractive solution for energy autonomy given the country’s reliance on imports for 97 percent of its gross domestic energy needs. In 2009 energy from non-fossil fuel sources (including hydro over 1 MW) accounted for 11 percent of energy consumption. Limiting the analysis to domestic electrical energy production, however, Italy, with its absence of nuclear power, is highly dependent on thermo-electric generation (77 percent in 2009). In 2011 Italy generated approximately one-quarter of its electricity from non-fossil fuel energy sources, with large-scale hydro accounting for the lion’s share.

The KMPG definition of renewables excluding hydro over 1 MW describes technologies used to generate electrical energy without use of fossil fuels or nuclear power — and, most importantly, as not having reached grid parity and therefore in need of incentives (wind, PV, biomass and biogas, geothermal and mini hydro). By this definition, in 2010, of 106 GW of electrical generation capacity and an annual production of 299 TWh, thermal electricity generation, hydro and renewables accounted for 74 percent, 17 percent and 9 percent of national electrical energy production respectively while having 71 percent, 16 percent and 12 percent of capacity. From 2005 to 2010, production from traditional thermal electric generation actually decreased by 10%, while hydro’s share increased by 40 percent and that of renewables by 100 percent.

During these years, as the economic recession led to decreased electricity consumption, renewables reaped the advantage of their ‘dispatch priority’ at the expense of traditional thermal electricity generation. From 2005 to 2010, the contribution of renewables to domestic electricity generation increased from 5 percent to 9 percent.

Distribution of renewable technologies in Italy's regions

The PV incentive scheme seems to have been successful in decentralising power production. While in 2010 there were 871 thermal electric installations and about 1000 for hydroelectricity, renewable energy sources accounted for 159,000 installations, with PV alone accounting for 98 percent of these.

Based on data from Terna S.p.A, the owner and operator of the national high-voltage electricity transmission grid, the report spotlights the remarkable growth rates of the PV, wind and bioenergy sectors. From 2005 to 2010, installed capacity in PV increased from 7 to 3,500 MW — a CAGR of 246 percent compared to a CAGR of 29 percent for wind which, with almost 6 MW of installed capacity in 2010, accounted for 45 percent of renewable energy production capacity.

When it comes to actual electricity production, however, wind, geothermal and bioenergy carry the day. In 2010 geothermal, with only 6% of capacity, accounted for 19 percent of electricity generation while bioenergy, with 18% of capacity, accounted for 34% of production, reflecting the relatively higher load factors of these technologies. Wind accounted for 32% of electricity generation, mini-hydro for 8%, with PV accounting for the lowest share at 7% or 1.9 TWh.

Though some form of renewable electricity generation is present in all 20 Italian "regions" (the highest-level administrative divisions of the state), the distribution of renewable technologies throughout Italy reflects its diverse geography. In the northern macro-region which includes the Alps, the major industrial centres and the agricultural plains of Lombardy, Piedmont and Veneto, bio-energy and mini-hydro account for 64 percent and 25 percent of electricity generation from renewable resources. In the central part of the country, on the other hand, geothermal resources are the major renewable electricity generator, accounting for 77 percent of production, all of it concentrated in Tuscany. In the windy south (the macro-region is defined to also include Sicily and Sardinia in addition to the southern regions), bioenergy accounts for 28 percent and wind power for 65 percent.

The southern macro-region, as defined in the report, accounted for half of renewable electricity generation in 2010. Tuscany alone accounts for a fifth of Italian renewable electricity generation followed by Puglia (13.6 percent) and Sicily and Lombardy with approximately 9 percent each. Wind is an important resource in the two southern regions whereas in Lombardy, where the highly polluted air rarely moves, the major contributor is bioenergy.

While this uneven development is largely attributed to the terrain and climate, the report suggests it may also reflect the fact that complicated regulatory processes and grid connection requirements can vary considerably from region to region.

One of the main original contributions of the report is a section benchmarking a sample of 25 companies operating in the Italian market based on publicly available financial data. The companies were chosen as being key players and have been categorised into three clusters. The first consists of eight traditional energy players (of which three are Italian) with divisions for renewable energy: Enel Green Power (really the major player), Alpiq, BKW, EDF Energies Nouvelles, Edison, E.ON Climate & Renewables, International Power (GDF Suez) and Sorgenia. The second cluster is composed of nine Italian industrial players which have diversified into renewables. The final cluster, designated "startup," is a catch-all term for some independent companies which, by and large, focus on the development of renewable energy. Warning that "this is a dynamic business with very heterogenous players" and that "it’s a model difficult to depict unequivocally," the report offers a summary of profitability and diversification of these major players.

The total sample accounted for around 5,400 MW of installed capacity in 2010 or 43 percent of national renewable energy capacity. Of this, the group of eight traditional energy companies account for 24 percent of national installed capacity while the other two clusters each account for around one-tenth. The major energy players are found to be providing almost 100 percent of geothermal electricity generation (monopolised by Enel Green Power), 69 percent of wind power capacity (4,000 MW) and 20 percent of bioenergy.

The bioenergy sector shows a medium level of concentration with the five largest operators accounting for 17 percent of national capacity while the PV market is extremely fragmented: the five largest account for only 4 percent of installed capacity as a result of the low capital cost of entry. The sample collectively accounted for 30 percent of renewable electricity production in 2010 or around 8,700 GWh. The sample companies focus their electricity production in the southern macro region where the companies in clusters two and three have 94 percent of their installed capacity.

For Attanasio, one of the surprising findings of the study is the relatively high yield of investments in this sector. While acknowledging that it is not possible to estimate the unique contribution of renewables from overall corporate activities for most of the traditional energy companies in the first cluster (for example, Enel Green Power), the analysis finds that the ratio of profitability (as measured by EBITDA margins to revenues) is relatively high for clusters two and three. While the majority of companies have revenues under €100 million, the EBITDA margin falls between 35 percent and 90 percent with a solitary exception.

Attanasio feels that this points to subsidies for the sector as having been too high from a long-term perspective. Installed capacity, particularly in the PV and wind sectors, has rocketed between 2005 and 2010 — but at what cost? The report emphasises that it has been difficult to achieve equilibrium between continued financial support and the attainment of grid parity.

The analysis clearly identifies how sector growth rates do not necessarily correlate with contribution to renewable electricity generation, as in the case of PV with its phenomenal growth rates and low contribution. Attanasio believes that what the country needs is a comprehensive national energy policy, not a hastily cobbled patchwork of incentives for various renewable energy sources.

Currently there are two basic types of incentives: market incentives (Green Certificates) and administrative mechanisms such as the all-inclusive tariff and FiTs. The Green Certificate scheme applies to all renewable energy sources (except PV) and to all installations which commenced operations before the end of this year. Energy is sold at the market price plus the value of the incentive as determined by the market; the incentive has a 15-year lifespan. However, as this mechanism is gradually being phased out to be replaced with FiTs, for Attanasio the key issue now is the uncertainty surrounding incentives for wind and biomass. In the past energy policy was often heavily influenced by key players, but with a government that seems to be taking snap decisions before it can be influenced, it remains to be seen how the battle will play out.

Another scheme, the ‘all-inclusive tariff’, offers smaller renewable electricity generators from all sources (except PV) an alternative to the Green Certificate Scheme whereby the energy is sold at a price that includes the incentive. The size cutoff depends on the technology: 1 MW for bioenergy, cogeneration, mini-hydro, tidal energy and geothermal and up to 200 kW for onshore wind installations. The incentive applies to installations which enter into operation before the end of this year, and has a duration of 15 years.

The PV sector, on the other hand, has been supported through FiTs, with the rates varying through successive plans (Conto Energia). The most recent and fourth version (IV Conto Energia), announced in May 2011, once again redefined 20-year incentives for PV installations which commence operations before the end of 2016. (All of these schemes were preceded by CIP6 from 1992 to 1999. With a 15-year lifespan it will end soon, and thus doesn’t apply to new market entrants).

The incentive schemes have been costly: increasing from €1.7 billion in 2008 to €3.4 billion in 2010 and to an estimated €6.4 billion in 2011. Of this cost, 80% is the so-called A3 component, shouldered by the final consumer through electricity bills. Given the unpopular austerity measures announced by the new government, how long will the public continue to support this sector?

Alarm bells have rung for the PV sector, which saw incentive costs spiral from €110 million in 2008 to an estimated €3.5 billion in 2011. In contrast, the cost of the Green Certificate scheme doubled from €615 million in 2008 to an estmated €2.1 billion in 2011. While installed capacity has doubled, the cost of the incentives has more or less quadrupled. PV is singled out as being under-optimised given the high level of expenditure per TWh.

Notwithstanding these criticisms, however, the report outlines how the renewable energy sector has been popular as a cautious investor choice for project financing, second only to telecommunications in terms of the value of financing. The country’s two major banks, Unicredit and Intesa Sanpaolo, together account for a third of the total number of projects financed and just over 40 percent of the cumulative value of €50 billion financed until the first half of 2010. However, given the future uncertainty related to incentives, Attanasio believes there may be a shift towards leasing or corporate financing in the future.

Now all eyes are on the new government to see what will happen. The new Minister of Economic Development specialises in leading companies, most recently in banking. His counterpart at the Ministry of Environment was until recently the Ministry’s director general. He’s a specialist in workplace and public health who has been involved in environmentally sustainable initiatives throughout his career. They are described as having little in common except their first name: Corrado. But in the Russian roulette of Italian politics, just perhaps it will be enough.

Cape Wind Gets a Big Break As Wind’s Tax Break Gets Stopped

U.S. offshore wind is celebrating as the rest of the wind industry scrambles.

Greentech Media By:Herman K. Trabish: February 17, 2012

Congress failed to include wind’s Production Tax Credit (PTC) in the deal on the payroll tax holiday extension. Without a PTC extension, the wind industry will likely see frantic activity in 2012 and fall off a cliff in 2013.

Every turbine built by December 31, 2012 qualifies for a 2.2-cent tax credit for every kilowatt-hour generated over 10 years. Getting towers into the ground this year will therefore take preference over preparation for U.S. development beyond this year. Developers have already begun walking away from 2013 and 2014 projects.

They have also begun preparations for future development in places like Latin America, Southeast Asia, and Turkey where federal supports are in place.

U.S. manufacturers will fill orders placed last year and early this year. They will then begin looking for other industries that need things like ball bearings, bolts and blade resins. Construction workers won’t have a moment to catch their breath between jobs this year, but will begin thinking about other industries on New Year’s Eve.

Some hopeful Capitol Hill insiders predict Congress will, with the November election behind them, pass the PTC in a December lame duck session. But the damage will have already been done.

When Congress used the PTC as a political football and allowed it to lapse in 1999, the wind industry’s installed capacity fell 93 percent the following year; when it did so again in 2001, the drop was 73 percent. The 2003 lapse produced a 77 percent drop.

This time around, impacts are likely to be worse. In the early 2000s, no more than 25 percent of a turbine’s 8,000 to 10,000 components were made domestically. In 2011, over 60 percent were.

The economic impacts will, according to a study by Navigant Consulting for the American Wind Energy Association (AWEA), be large enough to have state, regional and national economic repercussions. Without a PTC, Navigant predicted, the country will likely lose nearly 40,000 of today’s jobs and nearly $10 billion from the current economy.

Navigant also predicted that if the PTC were, like the solar industry’s investment tax credit (ITC), extended through 2016, the U.S. would add more than 25,000 jobs and a billion dollars in investments.

The same day that Congress turned its back on the wind industry, Massachusetts governor Deval Patrick announced a huge break for Cape Wind, potentially the first U.S. offshore wind project.

As part of its merger with Northeast Utilities, Massachusetts utility NSTAR agreed to a power purchase agreement (PPA) with Cape Wind for 27.5 percent of the proposed project’s 468-megawatt nameplate capacity.

Cape Wind spokesperson Mark Rodgers called the PPA “a major step forward for Cape Wind” and said it will “help clinch the first-mover advantage for Massachusetts in this emerging offshore wind industry in the U.S.”

In December, the Massachusetts Supreme Judicial Court (SJC) ruled acceptable the price approved by the state Department of Public Utilities (DPU) for the PPA between Cape Wind and New England utility National Grid for 50 percent of Cape Wind’s output. The NSTAR PPA will be structured similarly and is unlikely to be challenged.

The National Grid PPA’s first-year price of 18.7 cents per kilowatt-hour, increasing 3.5 percent per year for the 15-year contract, was challenged by project opponents who argued it was a burden on Massachusetts ratepayers. The SJC ruled that Cape Wind has “unique attributes” and offers National Grid’s customers benefits unavailable from other renewables.

Cape Wind-generated electricity is, for instance, available at peak demand periods, Rodgers noted, and often beats the peak period spot market rate. A Charles River study, Rodgers added, found Cape Wind’s electricity could save the state’s electricity customers “billions” and help meet the mandated 15 percent renewables by 2020 requirement.

The PPA was, however, structured on the assumption of incentives. In the absence of a PTC, Rodgers said, the project and the ratepayer will share an increased cost burden, and that makes things “more challenging.” But Cape Wind was proposed over a decade ago and has fought a host of challenges. “We’re determined to move ahead and we’re going to make the project happen.”

Though it would be possible for Cape Wind to sell the remaining 22.5 percent of its output in New England’s high demand electricity spot markets, the “preferred option,” Rodgers said, “would be to find other long-term power purchase agreements.” The combination of the NSTAR deal and the unanimous SJC ruling will, Rodgers said, “help our efforts to market the additional power.”

With DPU approval of the NSTAR PPA, Rodgers explained, Cape Wind will be able, at long last, to enter the financing stage of development. In its review of the National Grid PPA, an independent consultant estimated the project will cost $2.6 billion, according to Rodgers.

Cape Wind will be built in Nantucket Sound, five to 13 miles off Cape Cod. It will use Siemens 3.5-megawatt turbines, which have a proven record of reliability in European offshore projects.

An onshore interconnection for Cape Wind at the Barnstable substation on the coast of Cape Cod has been approved by the state and by ISO New England, Rodgers said. The goal now “is to begin construction sometime in 2013. It will take 2.5 years.”

By then, maybe even Congress will come around.

What’s Going On With Corporate Investors?

Rob Day: February 16, 2012, 8:55 AM

Walt Frick posted a good rebuttal to the Wired "cleantech bust" article recently, in which he points out that venture dollars into the sector remain high.

This is true, but as one of my fellow panelists at the Kellogg PE/VC conference yesterday pointed out, a lot of those dollars are simply follow-ons into existing investments. And furthermore, corporate investors have really been filling the gap recently.  One lawyer I spoke with recently who sees a lot of cleantech transactions told me that over the past 12 months, most transactions he's seen have included a strategic investor as the predominant "new money" in the deal.

It's clear that many large corporations have determined that there will be growth opportunities in emerging clean technologies, and at a time when many corporations have been hoarding cash they are thus able to put some money at work in venture investments in the sector.  This is very encouraging for the sector, of course.

But corporate venture investments have a history of piling on at the END of cycles. Does this current wave of investments portend bad things for the cleantech venture sector, given the lagging indicator they've often been?

The alternative optimistic view says that "this time is different", because various clean technologies are reaching a point of maturation where they are "ready for prime time" -- and this just happens to be at a point in time where corporations have capital and VCs don't.  And in addition, that the generally horribly ineffective channels for clean technologies means that large corporate partners do indeed have value to add, as opposed to other "bulges" in corporate venture investing, where they were just buying late into the party.

At the risk of saying "this time is different" (famous last words), I do tend to believe this latter, optimistic view.  Mostly because I don't see a lot of evidence that corporate venture groups are dramatically overpaying to buy their way into "hot" companies.  Indeed, I see a lot of bargain-hunting and serious evaluation of underlying technologies instead of just momentum investing among corporate VCs.  I do believe that many large corporations have determined that clean technologies will be strategic growth areas for them over the long run, and that now is a buyer's market so it's an opportune time to forge some relationships, investment-oriented and otherwise.

But even if so, there's still a significant disconnect going on.  While these corporate venture groups are investing in growth opportunities, the operating units within these larger companies are adopting cost-saving clean technologies as slowly as ever.

A long, long time ago, I and a colleague wrote about four different ways "sustainability" can be used to create economic value for large companies.  The first is simply to help ensure "right to operate" -- avoiding major environmental screw-ups.  The second is as a means of identifying cost savings via waste reduction.  The third is adding new products with resource-efficiency advantages, and the fourth is redefining the entire business.  More on this framework here.

Corporate venture groups are primarily concerned with the third of these opportunities -- new add-on businesses.  But there's a huge opportunity in the cost-saving category that is being missed by these same companies.

I see a lot of industrial energy efficiency startups right now, for example, that are having a hard time getting large corporates to act quickly to purchase new lighting / controls / etc. systems that would be relatively easy to implement and have compelling ROIs.  You would typically think that a 2 year payback period is a no-brainer for a corporate operating manager to pitch internally, yet I'm seeing even 6 month paybacks not get the traction you would expect.  Why?  Mostly because these aren't strategic priorities.

The corporate world has shifted a bit so that C-suites are often focused on executing on a top 3 set of priorities. And rarely is "make our facilities run more efficiently" one of these top 3 stated priorities.  Without a specific strategic mandate, the plant manager fights an uphill battle getting the CFO to pay attention, and the CFO doesn't want to spend time pushing these opportunities down on plant managers.  And then there's the "all the other stuff" dynamic -- plant managers have three priorities themselves: Production, safety, and all the other "stuff".  Energy/etc. cost savings falls into this distant third category.

I found it ironic that our cleantech panel yesterday was at the same time as a panel on how PE firms can create additional returns by driving operational improvements at their portfolio companies.  Ironic, because we should have combined the panels.  Indeed, thanks to efforts such as the Environmental Defense Fund's Green Returns project, PE firms are actually helping drive adoption of resource-efficient technologies pretty effectively within their portfolios.  

That's because they've made it a strategic priority (because it's such low-hanging fruit with rapid returns). But too often I go out and talk with a corporate venture group, and we'll be comparing notes on investment areas of interest, and they make it clear that their mandate only covers revenue growth opportunities, they have no ability to invest in technologies that could save their company costs.  Even at companies like WalMart that are doing a pretty effective job of making a priority of resource efficiency in their operations, the venture group is forbidden from investing in companies that could become vendors to their facilities.  

This is a major strategic disconnect.  And in my opinion, a mistake.  The most direct way to add to earnings per share is to reduce the costs necessary to create the same dollar of revenue.  But some of the very same large corporations now investing into somewhat risky cleantech venture capital deals aren't effectively adopting many of the readily available and proven technologies that could save their operations millions in costs.  You, Gentle Reader, are a shareholder in some of these companies, no doubt, so how do you feel about that trade-off?

If corporate leaders are indeed serious about driving future returns through investments in cleantech, they need to make sure that's an urgent priority for their Ops managers as well.  Cost savings through adoption of new efficiency technologies should be a priority at every large firm.  

If it takes your plant managers 9 months to agree to purchase a system that has a 6 month ROI, you're doing it wrong.

City of Palo Alto to Offer Feed-In-Tariff

What do Germany, Italy, Gainesville, Florida, Sacramento, California and Palo Alto, California have in common?

Well, as of March 5, all of those places will have solar feed-in tariffs (FIT). That's if Palo Alto's City Council passes the feed-in-tariff pilot program it has developed over the last few quarters.

It's a pilot program for the City of Palo Alto Utilities (CPAU) -- the first year is capped at 4 megawatts and meant for medium-sized commercial rooftops with a minimum size of 50 kilowatts per installation. The FIT is applicable to solar only, although other renewable energy sources could be considered later on. The city will pay $0.14 per kilowatt-hour for 20-year contracts.

Palo Alto is arguably the heart of Silicon Valley, home to dozens of venture capital firms and thousands of new companies armed with a startup and innovation culture fueled by its immediate neighbor, Stanford University. The city itself has about 26,000 electric meters and a peak load of approximately 180 megawatts.

The program limits itself to medium and large commercial solar rooftops in the interest of keeping workload issues to a minimum in the early stages of this endeavor.

The $0.14 per kilowatt-hour figure was based on the city's avoided cost. Here's the calculation:

• $0.070 for energy
• $0.034 green premium
• $0.006 local capacity value, essentially avoided distribution grid costs
• $0.019 avoided transmission access charges (TAC), an amount paid in California for every kilowatt-hour that is delivered from the transmission grid.
• $0.006 avoided transmission losses
• Total: $0.1355 per kilowatt-hour

So, the $0.14 per kilowatt-hour FIT price includes a $0.0045 premium and was agreed upon as a number that would attract developer interest. The cost of a fully subscribed program would be $29,000 per year; the city council estimates that the cost to the utility customer would be $0.01 per month. At this scale and modest cost, the city gains experience with the permitting, interconnection, metering, and billing process while developers gain experience in working with Palo Alto. (Note that Gainesville, Florida's FIT price was in the $0.26 to $0.32 range, which is good for developers, but perhaps not so good for municipalities.)

Craig Lewis, the Director of the Clean Coalition, a distributed generation advocacy group, attended the February 7 Palo Alto City Council meeting and commented that he saw this as "a good program, because it is constrained and not open to residential rooftops." He added, "It delivers the trifecta of being cost-effective, timely, and environmentally sustainable, and the pilot program is designed for success by avoiding pitfalls like dealing with tax complications of residential-level projects." 

"We think 14 cents is where participants can make a reasonable return," said Jon Abendschein, Palo Alto's Resource Planner.

Detractors of feed-in tariffs have claimed that the prices can never be set at a proper rate and that auction mechanisms are a more equitable solution. Others have argued that having no subsidy at all is the right solution. In the meantime, Palo Alto will likely have a FIT in place come March 5.