Like hundreds of thousands of Americans over three decades, I was in the Middle East, in uniform, carrying a gun to protect our national energy interests. A little over a year later, I took off from Bagram Airfield, returned home, and co-founded Sunrun to help American homeowners get their energy from clean, affordable, and domestic solar power.

There is nothing like a natural resource war to give you religion about renewable energy. Today we salute every American service member and veteran. Today we honor those who paid the ultimate price for our freedom and way of life.

Our way of life cannot continue to subsidize foreign energy sources with more blood and treasure. American soldiers, sailors, airmen, and Marines have and continue to make tremendous personal sacrifices to protect our national energy interests around the world. We have spent at least $7.3 trillion to defend our energy interests in the Persian Gulf alone over the last 30 years, according to research conducted by Princeton University professor Robert J. Stern. That  $7.3 trillion amounts to a massive oil subsidy.

To put this in perspective, $7.3 trillion equals 46 percent of our national debt today or approximately $23,000 per citizen. Imagine the last 30 years without two wars in the Gulf, with a better economy, and cleaner environment.

We owe our veterans and fellow citizens a way of life powered by clean, affordable, and domestic energy sources, like solar. Fortunately, we are making progress. In the first three months of this year, 82 percent of all new power generation built in the United States came from renewable energy sources. Every day, thousands of Americans buy electric cars and install solar panels on their homes. In many states, you can buy solar electricity for your house for less than you pay your utility today. You can run a car on that solar electricity for half the price of running one on gasoline. Those simple home economics mean we may not have to spend the next 30 years fighting debt-financed foreign energy wars.

Our military is leading from the front.

For example, the military is putting solar electricity systems on the roofs of buildings at bases around the country. That solar electricity saves the military money that it can invest in our national defense. Installing distributed solar electricity systems on military bases improves their defense by helping make bases self-sustaining and harder to attack. U.S. military units in the field are starting to use solar panels to generate electricity to run combat systems. Those solar panels make our fighting units more effective by reducing their reliance on vulnerable supply chains and expensive over-land diesel fuel deliveries for generators.

It costs the U.S. military approximately $50 for every gallon of diesel delivered to combat units in the field, according to the U.S. Marine Corps Expeditionary Energy Office.

An average solar panel costs approximately $150, creates as much energy as approximately 250 gallons of diesel fuel, and only has to be delivered once. Solar power is a force multiplier for us all.

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As a U.S. Navy officer, Nat served in the U.S. Special Forces in Afghanistan, where he was awarded the Bronze Star. He co-founded Sunrun in 2007. Today he is the President and CEO of Clean Power Finance, a leading provider of software and financial services to the solar industry, and a member of the Board of Directors of the Solar Energy Industry Association.

The bill contains so many smart new solar policies, we recommend a full read. Below we highlight some of the most exciting parts of the legislation:

1.5 percent Solar Energy RES Requirement

Investor-owned utilities (IOUs) must generate at least 1.5 percent of their total electric retail sales from solar sources by the end of 2020. Municipally owned utilities and rural electric coops do not have to comply with the 1.5 percent solar requirement. 

At least 10 percent of the new solar standard must be met by solar energy generated from solar devices of 20 kilowatts or less. The systems will be incentivized through a $5 million per year fund for the next 5 years. The incentives will be production-based, with a 10 year payment stream.

In addition to the 1.5 percent requirement, the bill includes language stating that it is a state energy goal (not mandatory) to get to 10 percent solar by 2030. However, the investor-owned utilities were able to get a provision in the bill that states that utilities can petition the Public Utilities Commission (PUC) to cap the total amount of net metered projects in their service district when it reaches 4 percent of gross sales. (Note  that this cap does not apply to VOST projects, and the cap only applies to IOUs.)

“Made in MN” Solar Module Incentives


The bill authorizes additional production-based incentives for systems that use “Made in Minnesota” solar modules. Payments will be set by the Commerce Commissioner and go to owners of grid-connected solar projects smaller than 40 kilowatts. $15 million is allocated each year for 10 consecutive years to finance the “Made in Minnesota” solar production incentives.

Expansion of Net Metering


The bill raises the net metering system size cap from 40 kilowatts to 1 megawatt for IOUs. The credit under net metering for excess generation from systems between 40 kilowatts and 1 megawatt will be avoided cost rate; projects under 40 kilowatts will continue to receive retail rate. Meter aggregation is now allowed as well, with systems receiving the same compensation rates as other net metering projects  and avoided cost credit for excess generation. However as you will read below, investor-owned utilities now have the authority to decide whether to continue offering net metering distributed solar projects or switch to a Value of Solar Tariff.

Value of Solar Tariff (VOST)

The legislation directs the Department of Commerce, Division of Energy Resources (DER) to develop a VOST rate calculation that utilities could opt-into in lieu of net-metering distributed solar facilities. The language on the VOST was carefully thought out by MN solar advocates, and will require the DER to consider all of the benefits that solar offers to the utility system, including: the value of energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The bill says the DER may also, “based on known and measurable evidence of the cost or benefit of solar operation to the utility, incorporate other values into the methodology, including credit for locally manufactured or assembled energy systems, systems installed at high-value locations on the distribution grid, or other factors.” 

Importantly, the value segments must be evaluated over the life of a solar energy system. Once the DER approves the methodology, the IOUs can plug in their own numbers and then apply to the PUC for approval of the rate. Of note, the PUC is not allowed to authorize a utility to implement a VOST tariff rate that is lower than the utility's retail rate until three years after the commission approves a VOST tariff for the utility. The VOST rate will be re-calculated and approved by the PUC annually. Additionally, VOST contracts will be twenty years (unless a shorter contract term is agreed to) and project owners compensated at a fixed rate.

Shared Solar - Community solar gardens

Vote Solar worked with Fresh Energy to ensure the bill included a shared solar component, an important way of broadening access to solar by allowing customers to invest in a solar project and get a credit on their utility bill, even if that project is not on their own roof. By September 30, 2013, Xcel must file a plan for this “community solar gardens” program, and other utilities can do so voluntarily.  The shared projects can be utility-owned or developed by a third party, must be 1 megawatt or less in size, and may have participants from the same county or any contiguous county as long as they are in the same utility territory as the shared solar facility.

Participants receive a bill credit for their portion of the energy produced by the shared facility, at the value of solar rate described below, or at retail rate if the value of solar has not yet been calculated. Other IOUs, such as Ottertail Power or Minnesota Power, may opt to file a community solar gardens program.

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Annie Lappé, Solar Policy Director at Vote Solar directs policy campaigns across the West and Midwest. Erin Stojan Ruccolo is the Director of Electricity Markets for Fresh Energy. Justin Fay is the Legislative and Policy Coordinator for the Sierra Club North Star Chapter.



 

Nest's founders, who came from Apple, worked on developing the first iPod. While a thermostat is a far different product from an iPod, that connection to a consumer technology giant inevitably brings up parallels between Nest's product and other successful mobile devices. And like Apple, the company is notoriously quiet about the upgrades it's working on.

In light of Nest's recent news, I spoke with Maxime Vernon, head of product marketing, about the company's latest technology developments and how it learns from its customers. Although Vernon wouldn't indicate Nest's next moves, its latest announcements may indicate where the company is headed.

Customer engagement and the need to "keep improving"

When it first rolled out in 2011, the thermostat's learning function, which was supposed to adapt to a homeowner's schedule, was criticized by users and reviewers for not working properly. Since that initial launch, the company has upgraded the device from the 1.0 version to a 3.5 version available today. The 3.5 version was the result of a "complete revamp" of the product six months ago.

According to Vernon, Nest "continues to fine tune even when we don't make an announcement" in order to update the Auto-Away and Auto-Tune functions. The newest version initiates the learning process in three phases (a set point and two user-initiated changes) that have supposedly make the function "much better this time around." The improvements have come through better data collection and analysis, which Nest doesn't comment on in detail.

In order to address criticisms of the product, Vernon said that Nest looked at every single piece of customer feedback from Amazon and app stores. "We tweak and prioritize based on what customers are telling us," he said. 

"All the recent upgrade announcements we've made have been based on learning experiences. We were able to gather all of this data, process it and learn from it," said Vernon.

The "Trojan horse" of thermostats?

After a bunch of companies, including Google and Microsoft, failed to get consumers engaged through home energy management platforms, the industry re-evaluated how to reach homeowners. Turns out, a simple thermostat has been a much better way to connect with consumers, thus opening up new opportunities throughout the home. Vernon called the learning thermostat a "Trojan horse" for home energy management.

According to Nest, the average customer interacts with the thermostat five times a day. "I can't think of any other thermostat that you would touch that often," said Vernon. 

Nest and handful of other companies are using this engagement to establish more active relationships between utilities and customers. Nest has set up new partnerships with Austin Energy, Green Mountain Energy and Southern California Edison to use the thermostat as a residential demand response device. In exchange for turning down a homeowner's thermostat automatically during times of peak demand, utilities will compensate customers. 

Don't call it demand response, however. "It's a bad name. No customer in their right mind would know what that means," said Vernon. Instead, Nest calls it "rush-hour rewards."

Working with utilities has always been part of the business plan, said Vernon, indicating that Nest has much more up its sleeve than a simple thermostat. Because the company has been forming those relationships since the start, it was able to announce those recent partnerships as a full-blown program, not a field trial or pilot.

"This is not a beta release. It's ready to be deployed. The thermostat is no longer just a nice-looking piece of hardware, but a tool to help utilities reach their mandates."

With its recent acquisition of MyEnergy to improve its analytics capabilities, Nest will likely continue to enhance those capabilities and roll out new programs.

Is it really like an iPod?

This is the question that Greentech Media Editor Eric Wesoff posed when Nest first launched its thermostat. His answer was "no." An iPod or iPhone are completely different than a thermostat, which can't "recreate the excitement of an entertainment product," he wrote.

Vernon somewhat agreed with that sentiment, saying, "The parallel cannot be totally true."

However, Vernon said that Nest is taking a page out of Apple's technology and marketing guidebook by creating a simple product and focusing aggressively on customer interaction. "One thing that Apple does really well is an extremely high [level of] attention to detail, high-quality materials and the focus on customer experience."

And Nest's experience last winter showed that customers may have a deeper emotional connection to the product than previously thought. On Christmas day, Nest saw its highest number of installs ever. The company never treated it as a traditional holiday gift when thinking about marketing, but it turned out that people were purchasing it as a Christmas gift and playing with it "like a toy."

"I understand it's not an iPod. But we do believe it's something that people increasingly want on their wall," said Vernon.

With its new retail presence in Home Depot and thousands of other stores, Nest is hoping it can blur the lines between exciting consumer electronics and historically boring devices like thermostats. It may just be working.

As for new upcoming features? Nest treats those like Apple does too.

"As a rule, we don't talk about future features. But when we look back, it's clear that we're learning a lot about how to make the product better," said Vernon.

Building on brownfields and landfills cuts down on -- or perhaps completely eliminates -- the kind of resource conflicts that have frequently plagued large-scale solar projects in California, particularly those on public lands. 

As a result of these minimized externalities, these projects were ushered through the permitting process by the state, receiving an enthusiastic “debut” at a Hackensack brownfield with the seemingly omnipresent Governor Chris Christie. Instead of litigious environmental review processes, and protests by activists, these projects appear to please everybody. There’s no “green-on-green” revolt, as the controversy over utility-scale solar in the West has been characterized in the media. There’s none of the escalating level of vitriol which has frequently flared up around these projects in the Golden State. And indeed, there are none of the significant environmental, archaeological, and social impacts associated with large-scale deployment of solar on previously undisturbed lands.

While critics have been predicting the end of the California solar gold rush, solar is booming in New Jersey, a rainy state possessing a solar influx comparable to that of Portland, Oregon, and yet which is second in the nation installed solar capacity, behind only California. The recent PG&E announcement will push New Jersey past 1 gigawatt of solar capacity, which on a per-capita basis far outpaces California.

As does Arizona, whose utility-scale solar installations are generally located on previously disturbed farmlands. The Grand Canyon State has a booming solar energy zone in the area of Gila Bend, Arizona, where farmland whose salinity levels got too high due to desert irrigation now is pumping out megawatts' worth of photovoltaic power. None of these projects have been marred by protest and rancor. California has the potential to follow suit as the Desert Renewable Energy Conservation Plan (DRECP), currently under preparation, is evaluating the prospects for appropriate solar development over the whole spectrum of lands in the California desert: public and private, pristine and degraded.

The EPA released a toolkit last year, the RE-Powering America’s Lands Initiative, which identifies contaminated lands and abandoned mining zones which would be appropriate for minimum impact renewable energy development. Arizona BLM actually took this a step further, conducting a survey of all public lands in the state that might be available for renewable energy development. The BLM pre-designated 192,000 acres (out of a possible 12.2 million acres) that were suitable due to minimized resource conflicts, pre-disturbance, lack of water impacts and other criteria. While development on these still-remote desert lands is not guaranteed to go as smoothly as has development on brownfields in mostly residential New Jersey, it is not likely to be as much of a lightning rod as the controversial Ivanpah project has been.

There are clear differences between the development of large-scale solar projects in New Jersey and the open spaces of the West, not least of which is the complicated politics of place. Nonetheless, when one compares the amount of money and time spent on mitigating the impacts of developing solar on undisturbed lands with the relative regulatory ease of building on contaminated or degraded lands, there is a clear advantage to the latter. While environmental regulatory inspiration typically flows eastward, at least in this case, California would do well to follow New Jersey’s example. The Garden State is pioneering bold thinking in the siting of solar facilities.

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Patrick Donnelly-Shores writes about energy policy issues for the UC Berkeley Energy & Resources Collaborative (BERC).

While detractors were declaring solar too intermittent to be reliable at home, U.S. Marines were successfully relying on it at battlefield sites in the Khyber Pass, according to Enlisting the Sun: Powering the U.S. Military with Solar Energy, a new report from the Solar Energy Industries Association (SEIA), released just in time for Armed Forces Day on May 18.

The DOD’s annual $20 billion energy budget makes it the biggest single energy consumer in the world.

USC 2911 of DOD’s title 10 Energy Performance Goals, as updated in 2009, requires 25 percent of total military facility energy consumption to come from renewable energy sources by 2025.

Driven by that target, the Navy has installed more than 58 megawatts at or near bases in Washington, D.C. and twelve states. It has plans to exceed the basic plan by obtaining 50 percent of its energy from renewable sources by 2025. Its plans call for 57 percent of its new renewables to be from photovoltaic (PV) solar through 2017.

The Air Force, the military’s biggest energy consumer, has built 38 megawatts of solar capacity operating in 24 states. It will procure 1 gigawatt of renewables by 2016. The plan is for PV to be more than 70 percent of all new Air Force renewable capacity through 2017.  

The Army has installed over 36 megawatts of solar installed at bases in sixteen states on its way to procuring 1 gigawatt of renewable capacity. Solar will account for one-third of the Army’s planned renewable capacity additions through 2017. 

By shifting Afghan remote bases to solar, the military has cut its consumption of generator liquid fuel from twenty gallons per day to 2.5 gallons per day, according to the report. The military pays $1 per gallon for liquid fuel and spends $399 per gallon delivering it to those remote bases.

Also highlighted in the report were solar innovations including:

• Portable backpack-mounted solar panels and solar tent shields capable of charging and powering communications, targeting, surveillance and security equipment
• A ground-mounted array at Forward Operating Base Geronimo, Helmand Province, Afghanistan
• The military’s leveraging of private capital through third-party ownership (TPO) financing and energy performance service contracts (EPSCs)
• The 14-megawatt SunPower-financed ground-mounted array providing 30 percent of the annual electricity needs at the Naval Air Weapons Station China Lake, California
• SolarCity’s Project SolarStrong, which has financed and built solar arrays at the Los Angeles Air Force Base, Schriever Air Force Base and other bases
• Honolulu’s Hickam Air Force Base solar community, where Project SolarStrong has installed 3.4 megawatts of rooftop solar on the way to creating one of the biggest solar communities in the world, with an eventual 5.5 megawatts that will serve 2,000 military homes
• A planned 24-megawatt, 6,500-home solar community at Ohana Military Communities which serves Navy Region Hawaii and Marine Corps Base Hawaii
• Solaria Corporation’s 4.1-megawatt, ground-mounted, low concentration PV installation at White Sands Missile Range in New Mexico that was part of a 25-year energy efficiency EPSC implemented by Siemens (NYSE:SI)
• The 2,200-unit solar water heating system installed at Marine Corps Base Camp LeJeune in North Carolina that will meet 75 percent of the camp’s hot water needs and cut its water heating costs by 20 percent

In this podcast, we talk with Dr. Dave Danielson, head of the office of energy efficiency and renewable energy at the Department of Energy, about the government's cleantech priorities in the coming year. A transcript of the conversation follows below.

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Dave Danielson: One area we've made a strong request for is for grid integration. As I'm sure you're all aware, we're getting to the point (especially with rooftop PV) where in the next five to ten years we're going to see broad cost-competitiveness with grid-based electricity, without subsidies in many parts of the country. At that point, we're going to have some significant challenges where we need to get utility business models and we need to get the physical grid set up in a way that we can continue to integrate very low-cost rooftop solar PV while maintaining the grid's reliability.

Because of this, we made a significant $80 million request for a new program that will work with utility and other technology partners in clean energy in order to develop the new technologies and utility market structures that will enable us to democratize the grid and enable high penetration of rooftop PV. That's one area where, if we do end up at a continuing resolution level or at that $1.8 billion, we won't be able to do nearly as much as we'd like to do in order to ensure that we can create an environment where rooftop PV will be able to continue to grow as it reaches cost-competitiveness, as opposed to potentially getting down if we don't solve these grid integration challenges.

Stephen Lacey: This is a really interesting point, because rooftop PV and other renewable energy technologies are to the point, now, where they are commercially viable. They are ready to hit the market, and many of the barriers in front of them are financial, market-based and policy-related. Given your experience at ARPA-E and as a venture capitalist, how do you balance the need for these market plays with the need for R&D, particularly as spending gets tighter?

DD: That's a great question and you're absolutely right. We have to allocate our limited dollars in a way that makes a difference. I'm always telling my team that we need to make "one in, one thousand out" kind of investments, because even with a budget level on the order of $2 billion per year, we're trying to move a multi-trillion-dollar-per-year energy economy.

To take a step back, when I sat down in this seat as assistant secretary a year ago, I really tried to understand where we were, what was unique about where we were compared to five to ten years ago, and where we would be five to ten years from now.

When you sit down and really look at the facts and figures and learning curves, the biggest thing that sticks out is that a wide array of these clean energy technologies (through the United States, EERE and by working with some of our best innovators) have really lowered the cost and increased the performance to the point where there's pretty clear visibility for a whole slew of clean energy technologies to direct cost-competitiveness without subsidies in the next five to ten years. That's true for solar PV, as you mentioned. For wind. For plug-in electric vehicles. For solid-state lighting. For solid-state transformers. There's a wide array of technologies.

In our budget request, the first priority is really driving hard on these technology areas where direct cost-competitiveness is going to be achieved in that next five to ten years, and making investments to ensure that the United States is the nation that's actually going to get a dominant share of the economic value-add associated with the technology's deployment when it hits the hockey stick curve. So, we're making those kinds of investments both in manufacturing R&D and in breaking down market barriers. At the same time, we have a balanced portfolio investing in the longer-term game changers.

Let's take the example of solar. We launched a new Grand Challenge a couple of years ago called the SunShot Grand Challenge. I was the co-chair organizing our workshops to develop our vision around what the Grand Challenge should be. What we noticed is that for the longest time, the module costs had been the longest pole in the tent. However, when we looked at where we were about two years ago, it was suddenly obvious that soft costs weren't coming down.

If you look at where we are today on the order of, I believe, about $2.50 per watt in the field, we've got to get down to about $1.00 per watt in the field -- which is the SunShot 2020 goal -- and the majority of the work we need to do is in the soft costs. In the 2014 budget, we're significantly increasing our efforts on soft costs, and those are really partnerships we want to develop with utilities and state and local authorities to cut through the red tape. We want to make sure that solar is getting treated fairly as a distributed resource and that we can break down these bureaucratic barriers, in addition to driving hard on manufacturing competitiveness.

SL: And that's an interesting story. That changed over time in consultation with the industry. It was really focused on R&D for technologies and on solar manufacturing. Then it evolved into understanding the market-based barriers and soft costs in solar. How did that change come about over time?

DD: For many years, the long pole in the tent was the module cost and performance. Going back to the 1980s with NREL and some of the early work that fed into the beginning of solar's success, ultimately a lot of the R&D made a big difference and really helped get us to where we were two years ago where we saw the crossing over of module costs and soft costs. Again, the soft cost learning curve just was not coming down -- it was very flat -- as opposed to the learning curve with modules coming down rather quickly.

It was a little bit of a culture shift, and I think it's the kind of culture shift that we're undergoing as these technologies are getting closer to cost competitiveness. A bigger part of our role, now, is to be an honest broker to break down some of these market barriers and to eliminate red tape so that these technologies can naturally fall into the market by economic gravity as they actually reach direct cost-competitiveness.

SL: I want to talk about this manufacturing piece that's so crucial to the DOE's broader strategy. This is particularly relevant after a number of high-profile bankruptcies in the space, and DOE has come under fire for the Loan Guarantee Program. These attacks have been really political. But amongst it all, there is an interesting conversation about where the DOE is going and what role the government should play in manufacturing and in clean energy promotion. As we come out of the experience of the stimulus and we look at the portfolio of loan guarantees that have been issued, has the DOE has changed its thinking on how to fund these types of programs, particularly in manufacturing?

DD: Under my purview at EERE [the Office of Energy Efficiency and Renewable Energy], we primarily focus on research, development and demonstration. We are also working with our key stakeholders to break down market barriers that exist, whether we have to work with other agencies or other stakeholders to be at the point to really try to break down some of these barriers that exist to the deployment of new technologies.

On the manufacturing side, about a month ago, EERE launched a cross-cutting umbrella effort that we're calling the Clean Energy Manufacturing Initiative. The first step that I'm taking is in collaboration with our National Renewable Energy Laboratory. We're diving very deep on our attempt to understand the competitive advantage that exists for various technology supply chains and in various clean energy technologies. We are looking at China, South Korea, Germany and the United States and trying to understand where U.S. competitive advantage lies and where we may not have as much of a competitive advantage.

As we move into this era where manufacturing is going to scale in a very significant way, we also want to make sure we're investing toward our strengths or investing to shore up our weaknesses. For example, we don't have an advantage in low-cost labor and we don't want an advantage in low-cost labor -- but if we can be the creators of automation and use automation, then we can bring those jobs back here.

When it comes to the work we're doing, a lot of our focus has been in trying to create what's called an "industrial commons." We're a big part of the president's national network for manufacturing innovation. We're one of the major partners there. This is a network of institutes that you could consider somewhat analogous to the Fraunhofer Institutes in Germany -- these are $70 million to $120 million, five-to-seven-year cost-sharing programs that are really designed to help U.S. companies access next-generation manufacturing capabilities.

The first one we funded was with the Department of Defense in additive manufacturing (3-D printing) in Youngstown, Ohio. Just last week we released competitions for three more topics, one of which the DOE is sponsoring in the area of next-generation wideband gap power electronics manufacturing, which is an area that touches all different clean energy technology areas.

Those are really filling in the industrial commons, and that's been a big part of our focus at EERE. I think that the Loan Guarantee Program is outside of my purview, but the whole point of the Loan Guarantee Program was to help support next-generation leading edge technology scale up in areas that the private sector wasn't going to be able to fund on their own. There was an expectation that some of these technologies wouldn't make it, but that, in the long run, the net benefit to U.S. leadership and the U.S. economy would be greatly positive.

I think that the portfolio in the Loan Guarantee Program is still in the black in that way, and I think we're seeing innovative technology companies like Tesla Motors. Twenty years ago, if you asked anyone if there would be a new automotive company in the United States, they'd say no. Now we've got an automotive company like Tesla that is innovating and selling commercial products and making money.

SL: I think that's a really interesting point to bring up that often gets missed in the conversation around the Loan Guarantee Program. This is a portfolio-wide approach, and the vast majority of the investments are doing well. Given some of the strategies that you talked about, has the DOE specifically taken any new approaches as a result of the experience in manufacturing through the Loan Guarantee Program?

DD: I think that given how fast this market is moving, we're always having a dialogue about what the high-impact proper role of government is. I know your readers are very familiar with the solar industry, and that's an industry where there was a whole lot of overseas government intervention that really has tilted things in odd ways.

One thing that is exciting is you still see a strong thin-film solar manufacturing base here, and a really important part of that has been government support through the Export-Import Bank. I think that industry and government should be pulling together even more and responding to overseas policies to make sure we're getting our vectors aligned -- to make sure that we're supporting our industry in a proper, free-market-oriented way -- but that we're all pulling together to make sure that our competitive manufacturing companies are actually given a chance to succeed while trying to balance out the playing field a little bit.

One thing that is under-appreciated (and we need to work to track the data a little better) is that ultimately we want to have as much manufacturing value-add in this country as possible. We want as much high-value, profitable manufacturing happening in this country as possible. When you talk to companies like 3M and DuPont and others, they're doing some very high-end innovation for some of the components in solar modules that are being assembled largely in China today. There's still a significant amount of economic value-add being accrued in the United States and exported, in this case, by virtue of us doing things that are very difficult -- manufacturing very high-tech materials or components.

I think that with this Clean Air Manufacturing Initiative here at DOE, we want to get even more oriented around where we have that competitive advantage and to make sure that when we take taxpayer funds and put them into some of this innovation, that we can see a pretty reasonable pathway to competitive manufacturing happening here, even in the context of other nations perhaps giving some pretty strong subsidies to their industries.

SL: One of the most interesting spending increases in this proposed budget is in energy efficiency. Is that an area where EERE wants to scale up? More so than in other sectors?

DD: Well, if you dive into the budget, you will see some especially significant increases in the Vehicle Technologies Office and in the Advanced Manufacturing Office. In this context, the Advanced Manufacturing Office is under our energy efficiency pillar from a sectoral perspective.

In the Vehicle Technologies Office, we're putting a significant amount of funding into the EV Everywhere Grand Challenge, which is a Grand Challenge that followed on the SunShot Grand Challenge with the vision of making the United States the first country to invent and manufacture plug-in electric vehicles that are directly cost-competitive and as convenient as gasoline-powered vehicles by 2022. That is more than $300 million we want to put into that effort primarily on next-gen batteries, with a major focus on really trying to push lithium-ion as far as it can go, but also investing beyond lithium-ion in a significant way for the first time here at EERE.

The goals that we want to get to by 2022 are very aggressive. We're currently at about $500 per kilowatt-hour on batteries. That's come down by a factor of two over the last four years with a lot of hard work. We need to get down by another factor of about four by 2022 -- down to $125 per kilowatt-hour -- to make a broad array of plug-in electric vehicles directly cost-competitive with gas-powered vehicles.

We're also driving hard on next-generation power electronics and motors, especially in power electronics on next-generation wideband gap semiconductor-based technology. This is an area (gallium nitride/silicon carbide) where the Department of Defense has made some very significant investments in the past in these materials, and now we think they're almost ready for prime time. The United States has a lead in this area, but we want to really accelerate our lead into some real commercial success in the clean energy area and, in particular, in the electric vehicle area. We're going big on EV Everywhere in this budget.

One thing that we've launched as a complement to EV Everywhere is something called the Workplace Charging Challenge. The president has laid out a challenge to some of America's greatest business leaders to sign up to poll their employees on their ownership or expected ownership of an electric vehicle and commit to provide charging at the workplace for their employees. We've got more than thirty partners in that. The EV Everywhere initiative is going well and we're putting a significant request in for that in FY14.

In the Advanced Manufacturing Office, we're investing in clean energy, energy efficiency and manufacturing competitiveness. One big thrust is working with industry to make them much more efficient and lower their energy costs to make manufacturing more competitive in the United States. This is an especially great opportunity for us to help industry innovate around integrating low-cost shale gas into their processes.

Secondly, we're investing in cross-cutting innovation. These are cross-cutting materials or manufacturing processes that, if we can successfully develop them, will have an impact on a whole array of clean energy technologies. An example of that is in carbon fiber composites. That's an area where we're investing in, in the Advanced Manufacturing Office. If we can dramatically decrease the cost of carbon fiber and carbon fiber composites, that will be a game-changer for lightweight vehicles, for high-pressure cylinders, for CNG and hydrogen storage, for vehicles and also for next-generation wind turbine blades. One of the major initiatives being proposed is to build out three more manufacturing innovation institutes and the president's national network for manufacturing innovation.

SL: And on the R&D side, you've got these eight new research incubator programs. Tell me about those.

DD: Those are something that I think is very important. When I got here about a year ago (maybe three or four years ago), I was actually employee number one at ARPA-E, so I'm very familiar with ARPA-E. Now coming into EERE, I've worked really hard to bring some of the best practices of ARPA-E over here, but I'm also committed to making sure we set up EERE and ARPA-E in a way that they really complement one another.

For the most part, EERE's model is to work with stakeholders and lay out a very bold, aggressive target for the industry in terms of achieving a certain cost by a certain year. I think the SunShot Grand Challenge is a great example of that. When we first proposed a dollar per watt by 2020, a lot of the stakeholders didn't take it seriously. As we've moved forward, it has become the new de facto goal.

Our approach at EERE is to lay out these long-term aggressive goals and then build long-term capabilities around the country to solve the problem. In doing that, we have to create a long-term game plan where we determine what technologies and approaches have the highest probability of getting us to that goal. And so inevitably, we can't focus on every single technology. What's great about ARPA-E? ARPA-E looks at our road map and tries to blow it up. It tries to say, "EERE is completely missing this new opportunity. Let's see if we can't fund some new technologies that really show promise and are off their road map."

The challenge we've had is to make sure EERE can quickly and easily onboard the technologies that are coming out of ARPA-E's pipeline that could be game-changers and really need to be brought into our portfolio. The incubator programs that we're proposing to introduce into each and every one of our ten technology offices are meant to devote about 5 percent of the funds into completely "off-roadmap" activities. It's really like an on-ramp for next-generation technologies (like ARPA-E technologies) to get into our EERE roadmap as quickly as possible as these exciting new opportunities present themselves.

SL: Are there any particular areas that you think are underserved in R&D that need to be addressed either at AARP-E or DOE collectively?

DD: I do think that there continues to be great opportunity and emerging opportunity in the grid integration space. It's interesting. Both from a market perspective and from a DOE perspective, they don't live in one place, and so there are a lot of different offices working on these challenges. In the last year or so, we've created a cross-cutting DOE grid tech team that is working together to really define a road map and a game plan, but I think we still have opportunity to continue to make more investments in that area that would have a lot of impact.

SL: How do you view these investments in a historical context? I think what we've seen in shale gas is very interesting, in that the Department of Energy and other agencies played a very important and direct role in providing R&D support, tax credits, grants, mapping tools and so forth for folks developing hydraulic fracturing technologies that many people thought wouldn't work. Now we're entering that same phase with technologies like enhanced geothermal with next-generation solar technologies and with advanced biofuels. I wonder if you see the development of those technologies in the same context.

DD: I absolutely do. I think that the shale gas story has been a phenomenally positive story for the nation all across the board in terms of the opportunity it presents for lower-cost, lower-carbon domestic energy. And as you said, there's a long history going back to the '70s of the DOE supporting some of the pioneering work when no one thought it would ever come to anything. Now, forty years later, it's a revolution.

It really highlights the importance of long-term thinking and long-term support for innovation in the energy area. It's interesting that if you just look at the simple learning curves and where we are, it is starting to feel almost certain that solar, for example, will become directly cost-competitive in my lifetime on rooftops and in the field -- yet there are still folks who remember ten to twenty years ago when that wasn't the case.

I think it takes a while to move people's impression of how close we actually are. I don't see any reason why thirty years from now we shouldn't have a whole lot of plug-in electric vehicles that people are powering up at home with a dollar per gallon equivalent cost of electricity. I don't see why people shouldn't be able to generate all the power they need within their home using the grid as a backup. I can see a world that's going to look a lot different and a lot better from an energy perspective in that thirty-year timeframe as long as we continue to support long-term innovation and break down market barriers to the introduction of innovative, new energy technologies into our energy system.

That’s the news from Fort Bliss, Texas, where the U.S. Army and Lockheed Martin cut the symbolic ribbon Thursday on the first Department of Defense grid-tied microgrid. The project, started in 2010, uses renewable energy (a 120-kilowatt solar array) and energy storage (a 300-kilowatt battery system), as well as the base’s existing backup generators, and ties it into a miniature grid via Lockheed’s Intelligent Microgrid Control System.

It’s not the first DOD project to combine on-site power resources like solar, batteries and backup generators into a self-sustaining, islanded grid unit -- in other words, a microgrid. In fact, the military is leading the charge in microgrids, given its need for fail-safe, always-on electricity supply, particularly when the bigger grid blacks out, no matter what the cost.

But Fort Bliss is the first Army microgrid project to hook itself up to the utility grid, which opens a new realm of possibilities, as well as challenges, for the system. That’s because, while the Fort Bliss microgrid is helping the Army meet its carbon footprint reduction and efficiency goals, its core purpose -- or “tactical utility,” as Fort Bliss spokesman Major Joe Buccino said in Thursday’s release, “is its ability to allow us to operate off the grid.”

“We are entering an age of emerging threats and cyberwarfare,” Buccino said. “We are assuming an unacceptable measure of risk at fixed installations of extended power loss in the event of an attack on the fragile electric grid." In other words, energy security comes first when it comes to the Army and the utility working together.

Microgrids: Islanded Today, Dynamic Tomorrow?

While the Army hasn’t disclosed how much power Fort Bliss uses, it’s no doubt much greater than the relatively small amounts coming from its 120-kilowatt solar system. While the Army is investing billions into solar and other renewable energy projects and recently announced a plan to build a 20-megawatt, $120 million solar PV plant at Fort Bliss in partnership with local utility El Paso Electric, its microgrid is still mostly powered by backup generators.

Likewise, the 300-kilowatt energy storage system is likely too small to back up the Army’s Brigade Combat Team complex where it’s installed, though the partners do say it’s “critical in lowering cost and maintaining a steady stream of energy,” as well as being able to respond to periods of high energy demand and cost to shave the base’s needs. 

So-called “islanded” microgrids, or those built just to power themselves independently of the grid, are still a vital asset for their owners. The Food and Drug Administration’s White Oak research facility in Maryland kept itself running during Hurricane Sandy with its always-on microgrid system built by Honeywell, for example.

Data centers, hospitals, airports and other critical sites often have backup generators and uninterruptible power systems that can do the trick of a microgrid during emergencies. Likewise, in developing countries like India, Brazil and South Africa, where grid power is unreliable and blackouts are a daily occurrence, many businesses have their own power supplies.

But most of these systems aren’t set up to interact with the grid when it’s still running. That’s too bad -- because the real benefits of microgrids to the grid aren’t simply tied to how much power they can supply themselves. More important is how they could interact with the grid as a dynamic resource, to do things like ease congestion, reduce peak demand or respond to grid emergencies.

That’s the potential that has many industry watchers predicting a surge in microgrid investment, though those predictions have a lot of variation in them, with forecasts ranging from $19 billion to $40 billion by 2020. Pike Research estimates there are 400 projects globally, but that includes plans that are still only on paper at this point. 

GTM Research sees more short-term opportunity for islanded microgrids, or those that aren’t built to interact with the grid. But in the longer term, “dynamic islanding will provide the biggest opportunity” for these systems to justify themselves on economic terms.

Building economically feasible, grid-interactive microgrids is harder than it sounds, however, with both technical and regulatory hurdles to overcome. Still, we’ve seen a few projects aimed at making it happen. The Illinois Institute of Technology (IIT) has built a $14 million microgrid, including renewables and flow batteries, with S&C Electric Co., for example. The University of California at San Diego has built a cutting-edge microgrid that supplies 90 percent of the campus’s power needs, and is being integrated into a larger microgrid project with utility San Diego Gas & Electric.

The Military Leading the Microgrid Charge

Breaking down the barriers between microgrids and utilities could open up a new world of opportunities for backup power systems to earn money when they’re not being used for emergencies -- in other words, almost all the time. The technical challenges of tying all these local grid assets together is the realm of big players like General Electric, ABB, Siemens, SAIC, Schneider Electric, Boeing, Honeywell and Lockheed, as well as smaller specialty technology firms such as Spirae, Integral Analytics and Power Analytics (formerly EDSA).

In the meantime, there’s a push into technology that helps connect microgrid capabilities to the demands of grid operations and energy markets, with players including the aforementioned giants, as well as startups like Blue Pillar, Viridity Energy, Powerit Solutions, Enbala and many others.

But the biggest driver of microgrids into the real world may well be the U.S. military. GTM Research has collected some data from DOD’s microgrid programs, which include interest and “prioritization” of research and development into inverters and switching, control and protection technologies, as well as the system design, integration and economic analysis tools that make them useful to their owners.

DOD and the Department of Energy are also working on standardizing the technologies that go into microgrids, via the Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) projects underway at Fort Carson, Colo. and at Pearl Harbor-Hickam Air Force Base and Camp Smith in Hawaii. Military microgrid developers include SAIC, Lockheed Martin, Power Analytics (formerly EDSA) and General Electric, which is already in a big microgrid project with the U.S. Marine Corps.

Jim Gribschaw, director of energy programs at Lockheed Martin, noted in Thursday’s release that DOD’s work could lay the technical and regulatory ground work for moving microgrid technologies for hospitals, universities, commercial businesses and industrial sites, to name a few potential customers of the “energy-efficient and secure future” it’s promising out of the technology.

GTM Research predicts that North America will be the earliest adopter of microgrid technologies, with resiliency, reliability and regulatory factors seen as key drivers. One key development is the new IEEE 1547.4 standard released in 2011, which covers the design and integration of microgrids into electrical power systems in a way that wasn’t permitted by previous standards.

At the same time, microgrids are popping up around the globe. The EU MORE MICROGRIDS Project has eight pilots underway led by a consortium of vendors, power distribution utilities and research teams from 12 European nations, and Japanese firms and organizations have nine microgrid projects ranging from 300 kilowatts in Albuquerque, New Mexico to 50 megawatts for the Miyako Island Microgrid, to name two noteworthy examples.

Hydraulic fracturing generally requires vast amounts of fresh water. Estimates vary widely, but water used for a fracturing job ranges from 40,000 to 60,000 bbls in the Delaware Basin, according to a Society of Petroleum Engineers paper authored by engineers from Halliburton and ExxonMobil subsidiary XTO Energy. Other sources, such as ALL Consulting, estimate per-well water use as up to 5 million gallons.

Common methods of disposing of water used in fracking include treatment and discharge to surface waters, deep well injection, storage in open-air pits and use on roads for ice or dust control, according to the Natural Resources Defense Council (NRDC). Various technologies also exist to clean flowback water so that it can be reused to drill other wells.

Oil and gas companies are under mounting pressure to address numerous water-related environmental concerns. These include the use of what may be scarce freshwater resources, especially in dry areas; truck traffic (with attendant emissions, road damage and noise pollution) to transport water from well sites to treatment or disposal sites; and the potential migration of contaminants from deep injection wells to nearby aquifers.

Of the above-listed wastewater disposal options, the NRDC says that only recycling and deep well injection should not be banned immediately.

Recycling flowback water has some advantages over injecting it into disposal wells. In addition to mitigating water scarcity and truck traffic concerns, disposal wells have also been linked to earthquakes in areas such as Ohio. Recycling can also be used for produced water, which comes out of the wellbore along with hydrocarbons, and flows continuously over the life of the well. This could offer further conservation possibilities.

Deep well injection has traditionally been the most cost-effective option, but oil and gas companies are not in a position to ignore public concerns over the impact of drilling on the environment, increasingly citing the need to maintain a “social license” to operate. “With the lack of fresh water availability in arid climates, it’s not only a pricing issue, but a water availability issue,” Ecosphere Energy Services Chief Executive Robbie Cathey told Breaking Energy.

“There’s no way they can just walk over these environmental issues, they’re going to have to address them very aggressively,” said Riggs Eckelberry, Chief Executive of advanced biofuels firm OriginOil.

Companies such as Ecosphere and OriginOil have developed various recycling techniques, with each company saying that its process is cost-competitive with injection into disposal wells. For more on these techniques, see part two of this three-part series: How It’s Done: Cleaning Up Fracking Wastewater.

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Editor's note: This article is reposted in its original form from AOL Energy. Author credit goes to Conway Irwin.

So has SolarCity. And SolarCity has decided to change its energy efficiency strategy. 

In October 2010, SolarCity added energy efficiency measures to its solar finance and installation business with its acquisition of Building Solutions, a software-enabled home energy audit firm. The founders of SolarCity have a background in enterprise software and were attracted to Building Solutions because of the firm's software capabilities.

SolarCity moved further into energy efficiency in 2012 with financing from Admirals Bank, and “by making energy-saving measures more accessible and affordable,” said CEO Lyndon Rive at the time. Admirals Bank, a federal savings bank with a history in home improvement, was to provide $2,500 to $15,000 per customer for efficiency measures to reduce a homeowner’s natural gas and electricity costs by 20 percent to 50 percent.

SolarCity had an in-house staff that was performing the tests and executing the efficiency improvements.

No more.

"We won't be self-performing," said Jonathan Bass, SolarCity spokesperson. Rather, SolarCity will make recommendations based on its audit and its software. "We’re actually expanding on the software evaluation side," said Bass, and "rolling out new services."

Bass promised a cool, new software product coming out by the summer. "We’re definitely changing the model in how we roll out the services," he said.

He stressed that SolarCity has done 15,000 audits. It's still in the energy efficiency business. It's just not going to be performing the efficiency work.

Bass said that was the best way to scale this part of the business.

"We’re going to continue to do energy efficiency. The services the customer receives will be the same. We’re going to continue to make recommendations; we’re just not going to do the efficiency work." He also noted that PV is a single service, while energy efficiency is a range of services.

A DOE study found that the U.S. spends $241 billion yearly on home energy bills. That’s one in five of the dollars the U.S. spends on energy -- an average of $1,900 per family.

However, there is a transformation underway that is uprooting this model. Since distributed energy -- including energy efficiency, demand response, distributed generation, and storage -- reduces consumer’s bills, the value it offers must be fairly accounted for and compensated.

A new paper from Travis Bradford of Columbia University and Anne Hoskins of Princeton University has tackled this issue head on, laying the groundwork for an expert energy policy roundtable that will aim to come up with a new model for valuing distributed energy. The full report has two important points:

1) A new valuation model must consider both the energy and capacity value of distributed energy. This requires understanding the difference between long- and short-term energy value, and accounting for the next best alternatives so that economic savings from avoided costs are included.

2) A new valuation model should consider both the costs and benefits of distributed energy. New technologies present new challenges and benefits that have nuances not always captured in traditional models. This includes cost-shifting to customers who do not use distributed resources, as well as benefits like hedging against volatile fuel prices. Other unique benefits can also be included, such as environmental preservation, greenhouse gas abatement, and job creation.

So how do you know what energy is really worth?

For starters, there needs to be a new understanding of the energy and capacity value of distributed energy technologies. Short-term energy value is usually the marginal costs of operation, including fuel costs and equipment maintenance. Long-term value is the average cost of capital investments and fuel over the life of the equipment. Either way, the criteria for determining the value of distributed energy would be based on “the value of the next best alternative for energy being fed into the grid at a specific place and time.”

Capacity value for distributed energy is assessed in capacity markets, which secure resources years in advance to maintain system reliability. The Effective Load Carry Capacity and Loss of Load Potential models are steps in the right direction, but most fail to incorporate the avoided costs from not building new transmission and distribution infrastructure. The bottom line is that variable resources like wind or solar can contribute to reliability even if they aren’t valued at 100 percent.

Considering the Full Range of Costs and Benefits

In addition to assessing the value of distributed energy, new technologies also have real costs. Those include loss of revenue, where generators will be online and wires will be transporting electrons, but increased use of distributed energy relegates the grid to “interim storage and backup supply.” The costs of operating and maintaining the grid are then shifted to other consumers. These costs may fall as the system downsizes to include fewer centralized generators and wires.

There will also be firming expenses as operational changes are enacted to manage a grid with higher penetrations of renewables, including forecasting technology and the costs of backup generation. Bidirectional electricity flows enable consumers to be transactional with the grid and leverage their personal resources like solar panels, but there will be additional wear and tear on circuits and costs for new security measures.

This is not to downplay the benefits. Reducing the need for transmission and distribution lines eliminates new construction costs, line losses, and congestion. Also, since electricity clearing prices are set by the most expensive unit required to meet demand, reducing peak demand means electricity demand is being met at a lower cost to consumers. Distributed energy is also a hedge against volatile fuel costs for coal-fired power plants and combined-cycle natural gas plants. Additional benefits, including environmental protection, greenhouse gas abatement, energy security, and local job creation, can be factored in as well.

Creating a New Valuation Model

Based on these findings, the authors suggest a new model for valuing distributed resources. The alphabet-soup version is "E+C-Co+Be+Ext." In layman’s terms, this means adding the savings from offsetting wholesale energy purchases (E) to the savings from avoided capacity investments (C), subtracting the range of costs listed above (Co), and adding the benefits (Be). The “Ext” part of the equation is the right of states to assess environmental, security, and job creation into the mix and value those benefits accordingly.

This is actually very straightforward. The equation boils down to valuing energy based on the savings from using distributed energy compared to using the next best option, along with considering the balance from a cost-benefit analysis perspective. There are a few real-world examples of this, but unfortunately, as the report notes, “none of them are comprehensive.” Examples include net energy metering, which allows consumers to be compensated for the electricity they generate, but only assesses retail energy value and not the long-term energy and capacity values or the costs and benefits.

There is also the Market Price Referent approach, which assesses the levelized cost of the energy by modeling cash flow for a proxy combined cycle gas turbine, factoring in capital costs, natural gas fuel costs, operations, maintenance, and environmental compliance.

Austin’s Value of Solar Tariff takes into account the avoided fuel costs for the marginal resource that isn’t being used, avoided costs of new capital investments to accommodate peak demand, avoided transmission and distribution investments and losses, and the environmental benefits.

Locational Marginal Pricing only values energy, congestion and losses, but in some places demand response is permitted to bid. State Integrated Resource Plans, long-term visions for a state’s energy mix, can also value distributed energy -- but few have.

The report is meant to inform and guide the discussion for creating a framework for minimizing costs, maximizing benefits and most importantly, finding the real value of distributed energy.

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Adam James is a Research Assistant for Energy Policy at the Center for American Progress and the Executive Director of the Clean Energy Leadership Institute. You can email him at ajames@americanprogress.org and follow him on Twitter @adam_s_james.