Author

John Farrell

John Farrell is the Director of Democratic Energy at the Institute for Local Self-Reliance. John is best known for his vivid illustrations of the economic and environmental benefits of local ownership of decentralized renewable energy. He’s the author of Energy Self-Reliant States, a state-by-state atlas of renewable energy potential highlighted in the New York Times, showing that most states don’t need to look outside their borders to meet their electricity needs. He’s also written extensively on the economic advantages of Democratizing the Electricity System, published a rich interactive map on solar grid parity, and polished the policies (like Minnesota’s solar energy standard) necessary to support locally owned renewable energy development.

Renewable Energy

Ejecting the Power Line Foxes from the Electric Customer Henhouse

written by John Farrell

The neighbors of the proposed Badger-Coulee high-voltage line in Wisconsin are like those in many other parts of the country, upset that their utility will construct 200-foot steel towers across their region and through their property (they have some other cogent arguments, too).

They should be more than upset.

In fact, all advocates of a smarter, cleaner, 21st century electricity system should be in a furor over the rules for building new high-voltage transmission lines that leave the transmission company fox in the ratepayer henhouse. These (mostly federal) rules violate the spirit if not the letter of the federal law requiring “just and reasonable” energy costs and significantly increase the cost of a low-carbon energy system.

The problem grew out of a 20-year federal effort to coordinate grid infrastructure investments that has inadvertently(?) undermined cost-effective alternatives to power lines. It has ballooned into a desperate need to change the rules of transmission planning.

Success with Coordination, but…

In the past two decades, Congress and the Federal Energy Regulatory Commission (FERC) have worked to make sense of regional electric grid planning, requiring coordination between utilities to for new grid infrastructure. That part has worked, with Regional Transmission Organizations (RTOs), largely run by the transmission companies, working together to plan new power lines. And they have come up with some ambitious plans, as the following map shows (existing transmission lines are in the darker, green shades. Proposed lines are in orange).

The problem is that this regionalization has almost completely undermined cost-effectiveness tests for new power lines. Regional planning has diminished the power of state Public Utilities Commissions, where there are (sometimes) meaningful consideration of alternatives to power lines for meeting electricity system needs (e.g. conservation, energy efficiency, demand response, distributed renewable energy). Transmission companies, often owned by monopoly utilities, have used their market power to set their prices without competition. In addition, the 2005 federal Energy Policy Act allowed FERC to provide incentives for new electricity transmission projects, a power they’ve used liberally.

Complete Failure with Cost-Effectiveness
In recognition of the failure to create meaningful competition and cost-effective planning for power lines, FERC issued a new order in July 2011 (Order 1000). The order meant to identify the most cost-effective strategy for meeting electric grid needs by including consideration of “non-transmission alternatives” when there’s a new power line proposed. These non-transmission alternatives – conservation, energy efficiency, distributed solar, energy storage, demand response – can often provide the same improvements to reliability, congestion, and power quality as new power lines, and at a lower cost.

Unfortunately, the order is toothless, allowing transmission companies to continue their plans for new power lines unabated, despite clear evidence of the value of alternatives. The following are three illustrations of cost savings through non-transmission alternatives (in addition to six potential benefits of non-transmission projects offered by utility regulation expert Scott Hempling in his thorough coverage of this issue):

“Con Edison was able to 1) reduce its projected capital expenditures on transmission and distribution by more than $1 billion by including energy efficiency and demand response in its forecasting; and 2) achieve additional savings of over $300 million by utilizing geographically targeted demand resources to defer investments in its distribution system.”

“The findings of ISO-NE’s energy efficiency forecasting initiative, applied to its transmission planning analyses…determined that 10 proposed transmission upgrades, totaling an estimated $260 million, could be deferred”

The Long Island Power Authority has promoted a 40 megawatt solar procurement program for the island that could help “avoid $100 million investment in transmission lines, distribution lines, in capital infrastructure…”

In spite of FERC’s new order, there’s almost no chance for non-transmission proposals like these to beat a power line proposal, no matter how much ratepayer money it saves.

No obligation to consider alternatives
While the FERC order requires transmission providers to give “comparable consideration” to non-transmission proposals that are proposed by participants in the regional planning process, the burden isn’t on the transmission company to offer the alternatives.

In other words, if no advocacy group or distributed renewable energy provider shows up (on their own dime) to offer an alternative to the transmission company proposal, then there’s almost no chance any non-transmission proposal will be heard at all.

Massive conflict of interest
Who chooses whether a transmission or non-transmission proposal is best in the regional transmission plan? The regional transmission organization, made up of power line companies. How do they make their money? Building power lines. But there are several layers to this problem:

Most transmission companies aren’t in the business of the transmission alternatives. In other words, to choose against transmission is to lose business.
Even if they had capacity to build a non-transmission project, FERC incents transmission over alternatives by providing bonuses to a transmission provider’s rate of return for building power lines (2005 Energy Policy Act, FERC Order 679).

No financial path for non-transmission
Unlike the rules for transmission lines, there is no regional process for cost recovery of non-transmission alternatives. In other words, the builder of a large and distributed solar project that serves the same needs as a regional transmission line has no certain method for recouping their costs, as they would with power lines.

There’s also no process for fairly allocating the regional costs of a non-transmission project as is done with a transmission line project. Consider this hypothetical example where the benefits of a $10 billion interstate transmission project could be served at half the cost by a $5 billion non-transmission alternative of distributed solar and energy storage. While the total ratepayer cost is $5 billion instead of $10 billion, a lack of regional cost allocation means that Illinois ratepayers would pay more for a project with the same regional benefits. And when that option comes before the Illinois Commerce Commission for “least cost” review, guess which wins?

Note: this is actually a kind of Prisoner’s Dilemma, an example of game theory of a situation where the game’s rules inhibit the most rationale response: to cooperate.

No evaluation of additional benefits
Unlike transmission projects, many non-transmission alternatives (like the one illustrated above) “provide further benefits by reducing energy costs, air pollution, and water used for [power] generation.” FERC and the regional transmission organizations don’t evaluate these factors, but state utility commissions and utility customers can. An evaluation by Vermont regulators shows a layer cake of value of energy efficiency to the state’s utility customers, only three slices of which (in blue, at the bottom) are likely to be considered by a transmission provider.

Serious Changes Needed
At stake is over $164 billion in transmission lines planned or under construction, with electric customers on the hook for that amount plus interest and guaranteed rates of return (with incentives!). How many of these projects were or will be approved without a meaningful look at cost-effective alternatives?

Change is needed. Now.

Utility regulation expert Scott Hempling offers three compelling amendments to existing policy, and I add a fourth:

FERC’s Order 1000 must be amended to require regional transmission organizations (or the companies that make up an unorganized “region”) to examine “all feasible non-transmission alternatives.” This analysis must be done by developing internal staff expertise at the regional level or contracting with an independent entity (not a transmission company or its subsidiary) that is expert in non-transmission alternatives. (Scott discusses a further scenario in his essay, for the very techically minded). This overcomes the “empty room” problem illustrated earlier, where the current order requires only consideration of those proposals submitted in the process (presumably by a third party) and it meets the threshold of prudent transmission planning as required in federal regulation.
FERC must reject any transmission company proposal for cost recovery without a reasonable investigation of alternatives. And “reasonable” should mean “an objective, regulator-reviewed process that identified and considered all plausible alternatives, and emerged from that process with the best benefit-cost ratio.”This is the key enforcement element.If FERC continues to approve cost recovery for transmission projects without proof of a robust and independent alternatives analysis, they are likely in violation of their charge to ensure reasonable and product costs.
FERC must develop (potentially via an amendment to the Federal Power Act) a regional cost-allocation process that puts non-transmission projects on cost recovery parity with transmission.As illustrated above with the Midwestern comparison, lower cost non-transmission alternatives will lose to expensive transmission projects in state regulatory proceedings simply because they lack access to the same regional cost recovery option.
State utility commissions should similarly reject any transmission line proposal, interstate or intrastate, that does not offer proof of a robust and independent alternatives analysis, and should build internal expertise to conduct such analysis. Citizens groups funded on $5 donations are often the only advocates for non-transmission proposals that can save electric customers billions of dollars over the financing life of power lines, up against entrenched monopolies with a shareholder interest in stringing wires. Public Utilities Commissions have a legal and moral obligation to stand up for cost-effective energy investments.

These policy changes don’t advantage distributed renewable energy or conservation or energy efficiency, but merely put it on a level playing field with profitable power line investments by transmission companies. They may give (modest) comfort to landowners that when utilities exercise eminent domain to use their land for new power lines, it’s only after robust and analysis of all cost-effective alternatives. Most importantly, they ensure that when we’re constructing a grid for the 21st century, for a majority clean energy system, that we’re doing it in the most cost-effective and prudent manner.

Oh, and it removes the decision over building power lines from the companies that make money doing it.

That’s not too much to ask.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

07/01/2014 0 comment

Renewable Energy

Forget Utility 2.0, Let’s Talk Energy Ownership 2.0

written by John Farrell

The transformation taking place in the electricity system is enormous, but twofold. But most commentators – including the former FERC chair – miss half the opportunity when they fixate on the inevitable technological rather than the more fundamental economic transformation.

The 20th century electric grid was characterized by two centralized components. The technology of power generation was centralized in large, fossil fuel and nuclear power plants, with transmission lines delivering this power to large cities. The economic ownership of the grid was also centralized within state-sanctioned monopoly utilities. Any third party ownership of power systems was tightly controlled through utility requests for proposals (RFPs) and bilateral power purchase negotiations.

A revolution in the electricity system is inevitable and in progress. Low-cost wind and solar power are leading a dramatic shift toward renewable energy, much of it built close to where power is consumed. This is what many people call “Utility 2.0″ (and I’ll explain shortly why that’s an apt name). But while the technology of the 21st century grid is already different, it remains to be see if we write the rules to seize the potential ownership opportunity.

Consider the situation with distributed solar power. It’s becoming so economical that utilities in California are buying solar energy in bulk from 100 megawatt (MW) or larger solar arrays at a lower cost than new natural gas generation, and made of the same 200-some Watt panels that grace residential rooftops. Even when buying lots of solar, as Xcel Energy is doing in Minnesota, the 100 MW worth of solar will be installed in 1-2 MW chunks at electrical substations across its service territory. The technological shift in power generation is inevitable. Utility 2.0 is coming.

The future of ownership is less certain.

Under net metering rules commonly adopted in over 40 states, the technological revolution leading toward local solar energy production is also shifting the economics of the grid. Solar-producing customers are curtailing their export of energy dollars to dirty, remote power plants in favor of clean, local energy. A decentralized method of power production is leading to decentralization of ownership, a democratization of power production and ownership. This dynamic promises more dollars to local economies just as it has lent more political support for continued expansion of renewable energy.

This is Energy Ownership 2.0, energy democracy.

Decentralized power generation technology is a prerequisite for energy democracy, but it’s not a guarantee.

Former FERC Chair Wellinghoff’s proposal to let utilities build and own behind-the-meter solar installations is a Utility 2.0 concept that falls short of energy democracy. In fact it may be as much an assault on the democratization of energy as the many utility-led fights against net metering. Although the full details aren’t available in the article, what’s clear is that he envisions utilities building distributed solar facilities, even on their own customers’ rooftops, and putting the cost (with a rate of return) into their rate base. He’s right that this would let utilities’ leverage their economies of scale and low-cost capital and that this is fundamentally different than getting their only rate of return from centralized infrastructure like utility-scale power plants and transmission lines.

It’s also the danger of focusing on “Utility 2.0″ rather than “Energy Ownership 2.0.”

In this Utility 2.0 model, utilities maintain their economic hegemony, and customers lose the opportunity to capture the economic value of their rooftop. Utility 2.0 explains how utilities will accommodate the technological transformation in the electricity system, but it assumes that they can and should remain the masters of the money.

The problem is that utilities that remain economic masters of the energy system will continue to have a conflict of interest between new, renewable, customer-sited power generation and their existing, dirty power plant assets. They will continue to fight EPA regulations and net metering and anything that undermines their ability to make money on power plants and power lines they already built.

If we stop at Utility 2.0, we allow utilities to use their customers’ money – lobbying the Public Utilities Commission, the legislature, etc – to defend dirty and outdated infrastructure instead of spending it on the tools – smart grids, energy efficiency, demand management – to reduce energy bills and carbon emissions, and that also encourage economic ownership by their customers. It will gut the opportunity for rural revitalization with renewable energy. It will slow progress in fighting climate change. It will be a halfway measure.

There’s a twofold transformation taking place in our electricity system. Let’s not settle for halfway measures.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

06/18/2014 1 comment

Renewable Energy

Local Energy Rules Episode 23 – San Diego’s Fight for Community Choice

written by John Farrell

“San Diego and its community choice energy district would be able to offer a diverse energy mix with all of the solar, biodiesel, biogas, and energy storage resources that we have in San Diego. A product that is price competitive and yet at the same time would strive for and achieve a higher level of renewable content.”

See how this southern California city is striving for more clean energy and more local control in this interview with Lane Sharman, co-founder and chair of the San Diego Energy District Foundation. This podcast was recorded via Skype on May 21, 2014.

A Fight Against ‘Solar Taxes’
The rise of the San Diego Energy District Foundation was in response to fees proposed on solar customers by San Diego Gas and Electric in October 2011. Thanks to the efforts of Lane, Bill Powers, and others in and outside of the foundation, the solar-crushing “Network Usage Fees” were not adopted. It was a particularly important win, because the fees would have applied to those customers who had already installed solar, with the expectation that they wouldn’t pay extra for going solar.

Pursuing More Local Energy Control
The Energy District Foundation wasn’t satisfied with stopping their monopoly utility from implementing bad policy, it wanted to create an energy system that put the community in charge of implementing policy that was positive for the economy and the environment. In 2012, members of the Foundation worked with Protect Our Communities, a nonprofit organization focused on using California’s community choice aggregation law, to create a local entity in charge of greening up the city’s energy supply with local power. They hope to follow in the footsteps of Marin County and Sonoma County in prioritizing local control of a cleaner energy system, at competitive prices.

Why Public Power?
The interest in local control over energy purchases is rooted in the inherent conflict of interest between ratepayers and their existing for-profit utility. Utilities in California make money by investing in hardware (power plants, power lines, and the like) and not finding the cleanest, lowest cost power for their ratepayers. In part, this is because taxpayers pick up the tab for pollution from fossil fuels. A public entity is more likely to incorporate those externalities. Water, sewage, and education all provide examples of where the public sector provides excellent local service.

How Renewable Can San Diego Be?
A 2010 study called the San Diego Regional Plan for 100% Renewable Energy outlines the technical potential for clean energy in the region. But it’s the market prices for clean power than are most encouraging. Open bids for new energy in Texas, for example, had solar bidding in at 5¢ per kilowatt-hour compared to retail energy prices of 15¢ or more. The county has approved (in 2013) a comprehensive energy plan that will include an investigation of a local energy aggregation.

A ‘Monopoly Protection Act’
Incumbent utilities don’t much like the San Diego Energy District Foundation and its plan for local control of the energy system. The big three corporate monopoly utilities in California are behind a new bill (AB 2145) that would completely undermine community choice aggregation by changing a key provision of implementation. Currently, when a local government establishes a local aggregation to purchase power on behalf of its residents and small businesses, these individuals may opt out. If AB 2145 passes, all potential participants would have to opt in. It effectively shields the monopoly utilities from competition, requiring a yet-to-be-operational local utility to spend thousands of dollars to attract customers before it sells a single kilowatt-hour. Furthermore, it would make energy procurement nearly impossible for the local utility, which would be unable to effectively plan and purchase power without a reasonable estimate of their market share.

For more information on community choice aggregation, Lane recommends the San Diego Sierra Club, the local 350.org, the Local Energy Aggregation Network, and the San Diego Energy District Foundation .

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

06/11/2014 0 comment

Renewable Energy

The Future of Solar Economics and Policy

written by John Farrell

Solar power is at a unique place in history. It’s growing rapidly, its price is falling precipitously. Within the next 10 years, it will compete favorably with utilities for electricity sales, on price, and without subsidies.

Given its rapid ascent, it might seem silly to talk about change. But the continued expansion of distributed solar power may rely on modifying a bedrock of distributed solar policy.

The Past

The solar past is all about net metering (and generous federal, state and utility incentives), a policy allowing smaller scale arrays (usually 1 megawatt or smaller) to connect to the grid at low cost, and for that solar energy to be credited to the producer’s electric bill as though it were a comparable amount of energy conservation. If a solar array produces 100 kilowatt-hours (kWh) in a month and the customer uses 300 kWh, then the customer’s bill is for the “net,” 200 kWh.

Why Net Metering is Awesome

Typically reduces or eliminates extraneous fees on producing local energy

Standardized tariff – same deal for everyone
Easy to understand compensation
Tax free energy production, because it is “paid” as an energy credit, not cash
Customer doesn’t need a battery because net metering is an accounting policy, not an electrical engineering one

Why Net Metering Isn’t Everything

You can’t produce more than you consume. If you’re a commercial warehouse with roof space for 2 megawatts of solar but very little on-site demand, it’s not economical to fill the roof with solar panels.
Compensation was historically much less than the actual value of solar to the utility, its customers, and society.
The customer may have a perverse incentive to increase electricity consumption because compensation is much less for energy produced in excess of consumption.

The following chart explains how net metering laid the financial foundation for solar PV projects, but that incentives had to make up the difference. It also illustrates how, based on the preliminary estimates of the value of solar from Minnesota‘s new policy, utility compensation for solar energy produced under net metering was likely far less than the actual value of that energy (unless the utility also offered rebates or incentives).

The Present

By the end of 2013, the U.S. had installed 13,000 megawatts (MW) of solar PV systems, and net metering contributed to a huge portion. The cost of installing solar had fallen 60% in five years and, in certain parts of the country, the cost of a solar array averaged over 25 years of energy production (called the “levelized cost”) had dropped below the price many customers paid to the utility per kWh. The following chart illustrates, with the levelized cost data for Missouri (about average for the U.S., but much above the cost in sunny areas like California or Colorado).

The growth in solar power and falling prices have led to a new dynamic in solar economics. For the first time in many places, solar electricity from the rooftop is cheaper than utility-provided power – without subsidies! And in particularly sunny places, the levelized cost of solar may even be below the “value of solar,” meaning that solar energy producers (if paid this value) could make a return on investment just on these merits. This “present” phenomenon will take place in different regions of the country at different times, but will happen everywhere within 5-7 years.

What’s important to note is that there’s a convergence: the retail electricity price, the value of solar, and the levelized cost of energy from solar panels are all relatively close.

It also means that by historical accident, net metering rates now and in the near future are very close to what solar energy is worth to the grid. And, it may mean that no incentives (local, state or federal) are needed to finance a solar project.

The Future

With a repeated nod toward the success of net metering and other incentives at building a growing solar market (at least in some regions of the U.S.), the future portends significant political problems if the policy prescription remains unchanged. The three key economic drivers of solar (the net metering rate, the value of solar, and the cost of solar) that have recently converged will begin to diverge rapidly. The following graphic illustrates the phenomenon that first strikes states with high electricity prices and abundant sunshine (already), but eventually spreads everywhere (in the next 10-15 years):

What does this divergence mean? Net metering will become increasingly lucrative for solar energy producers. For example, if Germany used net metering instead of a feed-in tariff policy, customers with solar arrays would be paid $0.30 per kWh for solar energy that cost less than $0.13 per kWh to produce, a 130% profit margin!

Big profit margins for solar producers is a novelty, but bad policy. First, it’s economically inefficient to pay so much more than is necessary to shift the grid to solar energy. Arguably, a 13% profit margin rather than 130% could move enormous numbers of utility customers to local solar energy. Second, when using net energy metering policy and paying a retail energy rate that is higher than the value of solar, it means that electricity customers as a whole are paying more for solar energy than its worth (assuming that the calculated value of solar is accurate). Finally, it’s inequitable. More than 75% of residents don’t own a suitable sunny rooftop for solar energy. If solar producers are getting over-sized profits, it comes out of the pockets of those who can’t afford to go solar.

But the economics are secondary to the political implosion that results from poor policy. Americans overwhelmingly love solar energy because it represents self-reliance, clean energy, and local power. It means monopoly utilities (which they dislike) lose and they win. It’s a political punch that unites the Sierra Club and Tea Party in Georgia. And it’s gone in a hurry if the evidence suggests that solar is perpetuating an economic system of winners and losers.

Already, utilities are fighting back against net metering and other distributed solar policies on the suggestion that the problems illustrated above are happening now (see the map of states where distributed renewable energy is under fire below). They aren’t. Utilities fighting now are fighting for a 20th century model of centralized control and comfortable monopoly profits. But in a decade they’ll have the truth on their side and not just innumerable lawyers and lobbyists.

So, what needs to be done differently?

Fixing the Future

No matter the changes, it’s important that the future distributed solar policy embrace the same principle as net metering: democratic access to the means of producing local energy with reasonable and equitable compensation.

Possibilities

The “value of solar” – change the form of compensation for on-site energy production from a per-kWh credit to a credit based on the true value of solar, as Minnesota has legalized. That state’s policy still uses the net metering framework (bill credits, matching production to onsite consumption) but changes the compensation from the retail energy rate to the transparent, calculated value of solar. Presuming the price is accurate, it can be enough to finance solar projects and hold non-participants harmless.

A Net Metering and Value of Solar Comparison

The following charts show how revenue from net metering and revenue from value of solar compare based on an actual 2.5 kilowatt (kW) solar array installed in Minneapolis. For a 2.5 kW solar array installed in 2014, the total revenue over 25 years is about $1500 more for net metering. For a solar array installed in 2020, the gap jumps to $5000. If the value of solar rate is an accurate representation of the actual value of solar to the grid, electric customers, and society, then the gap represents over-payment to solar energy producers.

Note: while the value of solar rate will change year to year for newly installed projects, it is locked in on a 25-year contract when a 1-MW or smaller project comes online. For more on Minnesota’s value of solar, read this report.

A feed-in tariff or CLEAN program – go a step further than Minnesota (and join Vermont, Hawaii, and various utilities like Consumers Energy in MI, Palo Alto in CA, and others) and use a policy that completely separates energy consumption from production. Set a price to pay for solar energy that grows the market or based on its value (both have been tried). Producers still buy all their energy from the utility, but they get paid for all their production (and likely pay taxes on it – after all, it’s income).
Something else entirely. Maybe 10 years from now battery storage is so cheap that everyone who has solar has one, and only excess power generation is sold to the grid at the value of solar. Or perhaps there’s community shared storage.

None of these ideas is the perfect fit for every state or every utility. And there are no doubt two other good policy concepts for each one I’ve listed here. But the future of solar energy will require a different approach than the past. And we’d best start thinking about what that future will be.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

06/04/2014 1 comment

Renewable Energy

Why is an Island Electric Utility Hindering Incredibly Cost-Effective Solar?

written by John Farrell

The Northern Mariana Islands are one of several island U.S. territories, lying three-quarters of the way from Hawai’i to the Philippines. Like most islands, their electricity supply has been almost entirely supplied by diesel-fueled generators, at enormous cost.

So why have islanders in the Marianas – such as the residents of Saipan – been struggling to install solar and other renewable power?

The utility, Commonwealth Utilities Corporation, has raised the same objections of mainland utilities, that technical barriers inhibit the reasonable uptake of variable renewable energy. But the cooperative utility serving Kaua’i island in Hawai’i is forecasting that 50% of its daytime electric demand will be met with solar by the end of next year. And California utilities are finding solutions to many of the purported technical barriers.

The economics are ironclad: switching from imported diesel to domestic clean energy would save a bundle. The following presentation explains.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

05/28/2014 3 comments

Renewable Energy

Local Energy Rules Episode 22 – A Deep Dive on Value of Solar and the Future of Solar Energy

written by John Farrell

“Utility regulation and rates is a contact sport,” says Karl Rabago, and that makes the implementation of a new “value of solar” policy complex. Will distributed solar grow better with a transparent, value-based contract price? How does it differ from net metering? Is Minnesota’s law a precedent to follow?

Prepare yourself for a deep dive in this extended interview with Karl Rabago, former Vice President at Austin Energy and soon-to-be Executive Director of the Pace Energy and Climate Center at the Pace Law School in White Plains, NY. This podcast was recorded via Skype on May 1, 2014.

An Accurate Incentive for Solar

A few years ago, Karl was interested in offering an incentive for solar energy production while serving as the Vice President of Distributed Energy Services for Austin Energy – the municipal electricity utility for Austin, TX – but he wanted to know how much to pay. Concerned about “feast and famine” effects of setting incentives, he wanted an accurate price that would grow the market but also reflect the actual value of solar.

Fortunately, he already had a good number.

Since 2006, the utility had been tracking the “value of solar,” based on a study conducted by Clean Power Research for the Austin utility. In the five subsequent years, the city had continued to track this value of solar.

If We’d Never Had Net Metering

Since the incentive program was new, it was an opportunity to re-think traditional policies for supporting distributed solar. Karl mused, “what would I do if we had never had net metering before – if we were writing on a blank slate?”

Traditional net metering (as implemented in Texas) provided two perverse incentives Karl wanted to avoid:

Because customers received a much smaller payment for excess power generation, they tended to increase their use to even out consumption and production, even during times of peak demand.
The retail rate isn’t set based on the value of solar energy.

With net metering already being destroyed by utility lobbyists in Texas, it seemed prudent to find an alternative.

“Solar Customers Know Their Electricity is Worth A Lot”
Although at first a shock, it became clear to the Austin utility and Karl that the value of solar was actual a premium over the retail electricity rate used to compensate net metered customers. In his words, it provided:

Fuel price volatility insurance

Insurance against climate change regulation

Insurance against drought

A Negotiated Shift from Net Metering to Value of Solar
Karl saw a potential negotiation with customers. The utility would pay the value of solar, and the customer would in exchange continue to pay for all of their power purchases, ensuring that they would cover the utility’s cost of maintaining its infrastructure.

“It was better for solar,” says Karl. The rebate costs have fallen by 33%, and solar installations have doubled since he left Austin Energy in mid-2012.

What Does it Cost to Serve a Solar Customer?
One of the biggest issues in the raging state-by-state debates over distributed generation is whether solar customers pay their fair share of the cost to maintain grid infrastructure. The bigger issue may be that no utility has ever actually studied the question:

“I’ve done only a couple hundred rate cases in my life,” says Karl, and “I have never seen a published utility cost of service study that shows how the cost to serve a customer with solar differs from the cost to serve an identical customer without solar.”

“The only real question” he says, is the potential uptake of solar between utility rate cases (if they don’t happen for a long time). And utilities already have a tool they use – a fuel cost adjustment that fluctuates with the price of fossil fuels – they could use. But Karl cautions that such a charge would be premature.

“In the mainland USA (outside of California), no utility has had their financial integrity threatened by the amount of solar that their customers have installed.”

Too Much Power for Utilities?

In the politics of distributed generation policy, value of solar is no different from metering.

“Utility regulation and rates is a contact sport,” says Rabago, and investor-owned utilities “owe a duty to their shareholders to try to maximize profit.”

For any policy, advocates will have to play defense or offense, but always be in the room.

A Right to Self-Generation?
Not in his reading of the law, suggested Karl. He believes that utility tariff law and PURPA provide a broader right, however, that customers should only have to pay for what they use. In that vein, he finds the notion of charging higher fixed fees on customers “silly.”

“There is nothing in Econ 101 that says that the way you collect your revenues has to be parallel to the way you incur your costs.”

Just because utilities find that more of their costs are “fixed” (poles, wires, transformers), instead of variable energy delivery, doesn’t mean that they have mimic that in their billing. He offers the anecdote of a coffee shop, which has high fixed costs but that charges its customers for what they use (the coffee they buy) and no more.

Utilities: Focused on the Small, Insignificant Things
Karl concludes his analysis of the utility attacks on distributed solar and other distributed generation with an anecdote from a utility board room. Looking for a scapegoat in an increasingly challenging market, utilities realize they have little control over the major factors: natural gas prices, energy efficiency, the weather, the economy.

“I have a sense that well-meaning people…are reaching out for the small, insignificant things because they can control them rather than facing a fundamental reality of the utility business that the largest, most capital-intensive business on the face of the earth is driven almost entirely by exogenous factors, commodity prices and the general state of the economy.”

The fight against value of solar or net metering is a fight against a changing business model, says Rabago, and change always comes hard.

Can We Get Along?
Karl notes that whether everyone loves value of solar policy, the notion of proper valuation for solar energy is supported widely. Cost-benefit studies of net metering for solar have had enormous support from advocates. Even The Alliance for Solar Choice, notable for its opposition to value of solar, has filed a brief in favor of proper solar valuation in a North Carolina regulatory proceeding.

Benefits to Value of Solar
While no policy is perfect, Karl sees several benefits to using value of solar policy.

It eliminates the argument about “cross subsidies” between solar producers an non-solar customers.
Customer gets full compensation for their energy production
Customer doesn’t have perverse incentives around energy efficiency, because reducing energy use (even for a solar owner) always means reducing their energy purchases.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

05/21/2014 0 comment

Renewable Energy

Sonoma Clean Power “CCA” Launches

written by John Farrell

Starting this month, 20,000 Sonoma County, CA, electricity customers will get more renewable power at a lower cost than from their previous utility, Pacific Gas & Electric. More of their $180 million in energy expenses will stay in the local economy. The portion of renewable electricity (“CleanStart”) for the average customer will rise by 50%. For those so motivated – 3% of customers already – it’s also possible to purchase 100% renewable energy (“EverGreen”) at a 20% premium to regular rates.

This new power provider is called Sonoma Clean Power, a nonprofit, locally controlled utility, delivering power to an aggregation of cities and towns within Sonoma County. It’s the second example of “community choice aggregation” to go live in California, following Marin Clean Energy‘s launch in 2010.

The concept gives more local control over the supply of energy to a community, but without requiring the city or county to purchase the poles and wires from the incumbent utility (as happens when the city creates a municipal utility). The following graphic (adapted from Sonoma Clean Power) explains the policy, available in six U.S. states:

More Renewable

Sonoma County and Marin County in California join many local aggregations buying electricity across the country, but few with as strong a focus on local, renewable power. Locally produced geothermal energy will provide 15% of Sonoma’s electricity mix, and the utility is offering a 1¢ per kilowatt-hour bonus payment to net metering customers who provide excess power to the grid. A feed-in tariff program to encourage more local renewable energy production will launch soon. Sonoma Clean Power is able to offer all these benefits along with rates 4-5% lower than the incumbent, Pacific Gas & Electric.

Clean, local power is not always the top issue for aggregations. The largest of them serve several hundred thousand customers in Ohio and Massachusetts, saving customers on their bills but including an electricity mix little different from the larger grid. Many recently launched aggregations operate in the Midwest, including Cleveland, Cincinnati, Chicago and hundreds of other Illinois towns. A fair number of these Midwestern local utilities have advertised 100% renewable energy, but with a catch. The electricity mix is mostly the same as the incumbent utility, but the towns have purchased renewable energy credits from existing wind power plants to “green” the supply. It’s an open question whether this process represents greening or greenwashing.

Sonoma Clean Power openly addresses this issue on their website:

For CleanStart, we keep costs competitive by buying about 15% of our renewable power in the form of renewable energy credits. The state’s system of credits is used by virtually all California electric utilities and allows us to reduce greenhouse gas emissions by buying power from the lowest cost producers in the Western U.S. without having to send the power over hundreds of miles of wires. It’s the industry standard for supporting climate benefits, but we recognize that it doesn’t do much to help our local economy. You can read more about renewable energy credits here, but our plan is to use them sparingly so we can support a clean and local energy economy.

More Local

The power aggregation also advertises local control, noting that its customers spend $180 million per year on electricity that otherwise would leave the community.

In the past, electric rates were set without any input from Sonoma County. SCP takes back control and gives us a voice.

In addition, the power agency will be able to exert more authority over the $12 million in energy efficiency dollars set aside by state programs for their customers.

$12 million is collected from Sonoma County ratepayers every year to use for energy efficiency programs, but ratepayers have no say about what programs are implemented—or where in the state they’re implemented. SCP will get a portion of that money to develop new programs that are customized for our local needs.

Under Fire, Again

California CCAs have led the movement in innovation around clean energy, but also in overcoming opposition. The Marin aggregation took nearly a decade to launch in the face of a massive, $46 million spending campaign by Pacific Gas & Electric to pass Proposition 16, which would have raised the voter threshold for forming local aggregations from a majority to two-thirds. The proposition failed and Marin and Sonoma have succeeded, but Pacific Gas & Electric hasn’t let up. Despite a 2011 state law prohibiting such activity, Pacific Gas & Electric has allegedly been spending ratepayer money to support a new bill that would undercut the formation of new aggregations by requiring customers to opt-in, rather than opt-out.

Of the six states with CCA laws, only New Jersey has such a provision and it’s also the only state with no local providers.

The battles over local control in California highlight one important political issue for community choice aggregation (CCA): whether the existing market is a regulated monopoly or allows retail competition. No CCA law has been adopted in a state where monopoly utilities hold sway, and California is the only state to have the program in the presence of monopoly regulation because it re-regulated its utility sector after a corporate-induced energy crisis.

Fortunately, the advocates of local control have proven stronger than the incumbent utilities so far. And the price and environmental benefits of Sonoma Clean Power, notwithstanding the localizing of energy dollars, shows that investing in local authority over energy means good things for electricity customers.

Further reading:

Our 2009 report, Community Choice Aggregation – An Update
Our story on Marin Clean Energy’s launch, and our recent interview with its Executive Director, Dawn Weisz
Our investigation into the use of renewable energy credits for green power programs in Illinois
The Community Choice section of our 2013 report, City Power Play

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

05/15/2014 1 comment

Renewable Energy

A Little Tapped City Strategy for Boosting Local Renewable Energy

written by John Farrell

Many cities served by private utilities think they have little capacity to encourage local renewable energy development. But a largely untapped tool – utility franchise contracts – may hold the key.

There are two kinds of city energy systems: publicly owned or privately owned. Cities with municipal utilities already have the power to implement the energy system that best fits their needs, and several such utilities have been leaders in energy efficiency and local renewable energy (see our City Power Play report). Cities with private utilities have felt relatively powerless, since these utilities are typically regulated by the state legislature or Public Utilities Commission.

But cities with private utilities may be overlooking a common legal tool governing the city-utility relationship, with a potential for revenue to support local energy development. These “franchise contracts” outline how a utility will use public property in order to deliver energy services. Think about the poles and wires running through a city neighborhood or gas pipelines running under streets, all of it public property and right-of-way.

Franchise contracts are typically renewed every 20 years, and are often renewed with little fanfare. But cities can use the expiration of utility franchises as an opportunity to discuss their energy future. Minneapolis, MN, for example, began a conversation about its energy future in early 2013 and prepared for the expiration of its city-utility contracts in 2014 by developing a detailed study of the “pathways” to a cleaner, more equitable, and more local energy future (scroll down for a brief slideshow of the study recommendations). The city is now prepared to create a novel city-utility partnership to meet its ambitious climate and sustainability goals

Franchise contracts can also be a source of revenue to support a clean, local energy economy. Many cities – several dozen served by Xcel Energy in Minnesota alone – already have a fee in place. Though not often done, this fee can be turned toward clean, local energy development.

For example, a local energy production incentive was explored in a policy paper developed by the Renewable Energy Task Force serving the city of Edmonton, using franchise fee revenue to supplement utility-provided compensation for renewable energy production. This “CLEAN Contract” would provide a long-term, production based incentive to complement revenue earned under net metering or similar policy. The following chart illustrates. The contracts signed in 2014, for example, provide a 3¢ per kilowatt-hour (kWh) bonus to net metering income, an amount that remains fixed for the duration of the (typically 20 year) contract. The contract price declines over time as the cost of energy from renewables continues to fall.

Franchise fee revenue could be used for a host of other tools to improve the capture of local energy dollars. Cities can motivate home- and business-owners to invest in energy efficiency by refunding energy audit fees to recipients who follow up on their audit by implementing energy efficiency measures. Franchise fee revenue could provide a loan loss reserve for an energy efficiency financing program like PACE, leveraging millions of dollars in private, low-risk loans for improving the energy use of local properties. Fee revenue could simply be invested in cutting energy costs of local government, whether through deep energy efficiency retrofits, street lighting upgrades, or on-site energy generation.

Many cities have aspirations to capture more of their local energy dollar for their economy, some are even motivated by larger environmental issues. Franchise contracts and franchise fees may provide cities with leverage and financial wherewithal to achieve a more local, equitable energy future.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

05/05/2014 0 comment

Renewable Energy

Local Energy Rules Episode 21 – One City Utility is Carbon Neutral, Today

written by John Farrell

It’s one thing to own your utility and have a commitment to renewable energy, but it’s another thing to deliver. The municipal utility in Palo Alto, CA, set an ambitious target of 33% renewable energy by 2015 and to ultimately deliver a carbon neutral electricity supply. They will reach 48% renewable power in 2017 and met the carbon neutral goal starting last year.

Learn more about the strategies one municipal utility pursued to drive down its carbon emissions and acquire solar energy in this interview with Jim Stack, Senior Resource Planner of the Palo Alto Utilities, recorded via Skype on Feb. 27, 2014.

How Can a Utility be Carbon Neutral?
The foundation of Palo Alto’s energy supply is hydropower, making up as much as half of their total electricity generation each year. But other renewable energy supplies the other half, at a time when most utilities have targets of 25% renewable or less. The chart illustrates how Palo Alto plans to get 23% of its energy from solar, 11% from landfill methane recovery, and 12% from wind power in 2017.

The carbon neutral target, while impressive, doesn’t mean that no fossil fuels are used. The statement means that on an annual, net basis, the cities electric customers produce no carbon emissions.

Building on Low-Cost Solar
The drive toward renewable energy and a carbon neutral energy supply was aided by dramatically falling costs for solar energy. When the utility went out for bids in 2012, it found solar producers willing to sell the utility power for 7¢ per kWh, a price that’s remained relatively steady since then. Low cost solar energy has meant that the city’s nationally recognized green energy purchasing program, with 20% customer participation, eliminated the price premium because clean energy was no more expensive than traditional power.

Having Control Matters
“If you were a customer of an investor owned utility, you’d be much less likely to see a program like [Palo Alto’s] put in place simply because investor-owned utilities have a much more traditional business model focused on profits and the bottom line,” says Stack.

Local control was a key to the success of the pursuit of a low-carbon energy system in Palo Alto. They aren’t hampered by regulators and the city’s bond rating means the municipal utility can also access lower cost capital than investor-owned utilities.

Municipal ownership has one big drawback, however, making the transition to renewable energy that much more impressive. The city can’t access the 30% federal tax credit for solar energy projects that private developers can. While they can still sign contracts with these developers to deliver solar, they miss the economic opportunity of direct ownership.

Keeping it Local
Palo Alto hasn’t been able to develop as much power in town as it would like, confesses Stack. As a mostly built-up urban environment with high land costs, and in a very sunny environment, local solar energy costs nearly twice what it costs to buy from projects nearby. All their renewable power comes from California, however, within a two hour drive of the city.

The city does have programs focused on local distributed generation and energy efficiency, however. Already, 6.5 MW of solar energy has been installed on local rooftops (serving about 4% of peak demand). The utility intends to use its feed-in tariff, community solar, and other initiatives to increase local solar to 23 MW, serving 15% of peak energy demand and 4% of total sales.

Can it Work for You?
Stack says there’s nothing stopping other municipal utilities from moving in the same direction. Renewable energy is less expensive than just about anything else and offers long-term price stability.

For communities without municipal utilities, he suggests lobbying for voluntary green purchase programs, community solar, and working on developing community-based renewable energy projects.

For more information on Palo Alto Utilities, see the section on Palo Alto in ILSR’s 2013 report showing 8 ways cities can boost their economy with local renewable energy: City Power Play.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

05/02/2014 1 comment

Renewable Energy

Community Solar Gardens Sprouting in Minnesota

written by John Farrell

On April 7, the Minnesota Public Utilities Commission resoundingly rejected (click the link for an annotated ruling) a severely lacking community solar gardens proposal from Xcel Energy and required substantial improvements for the utility’s revised filing.

The regulatory smack-down means a promising community solar market for Minnesota (scroll down for the infographic version).

The Basics
Advocates worked hard to make it easy to establish community solar projects, and the following basic rules apply:

Minimum of 5 subscribers (who cannot own more than 40% of output, each)
Minimum 200 Watt subscription (typically one physical panel)
25-year standard contract
Total project size can be up to 1 megawatt (AC)

Compensation

The utility (Xcel Energy) must purchase all energy from the community solar project, whether or not it is fully subscribed
For subscribers – utility must pay them the full applicable retail energy rate (like individual net metering), including for net excess generation (energy in excess of their own on-site use)
For unsubscribed energy – utility must buy power from panels that are not owned by subscribers at the applicable retail rate for projects smaller than 40 kilowatts (kW), but only at the avoided cost rate for projects larger than 40 kW
REC – $0.03 per kWh for < 250 kW, $0.02 per kWh for > 250 kW. Not eligible if project also gets Made in Minnesota or Solar Rewards
Applicable retail rate reviewed and adjusted annually.
Bill credits, month-to-month carryover, purchase at end of year (at applicable retail rate)
If and when Xcel Energy files to offer a value of solar price, it will supersede the above rates and REC prices (at time of publication, Xcel has asked the PUC to reconsider the value of solar)

Fees
1-time fees:

A $1200 application fee, refundable if the project is withdrawn
A $100/kW deposit, refundable upon project completion or withdrawal (with interest)

Ongoing:

Administrative (called “participation”) – $300 per year
Metering fee – $66 per year, three phase: $96 per year

Process
Applications are not processed in order of application, but are prioritized as “first ready, first served” to help level the playing field between large and small developers (the latter taking more time to apply, perhaps):

The project meets the definition of completeness in Xcel’s solar-garden tariff;
The project has obtained or arranged appropriate insurance or has entered into an insurance-broker agreement;
There is evidence of site control and a point of interconnection;
There is evidence of projected subscription at the time of construction; and
The project proposal complies with all applicable material terms of the tariff and standard contract and with any additional considerations that Xcel, solar-garden developers, the Department, the OAG, and interested parties participating in the solar-garden working group have agreed to include in the plan.

Despite utility efforts to curtail solar gardens, the PUC emphatically said that there can be no limit on the total installed capacity of solar gardens.

Killed
The following items were thankfully removed from Xcel’s original proposal:

A second deposit
A 2.5 megawatt quarterly limit on solar garden installations
Lower compensation, based on “average retail energy rates”
Capacity limits in DC instead of AC (about 25% smaller)

Will They Grow?
The Public Utilities Commission was very deliberate in identifying rules that facilitate a fair balance between ease of establishing solar gardens and protections for solar gardens subscribers. The PUC also endeavored to provide adequate compensation for solar gardens, setting solar REC prices based on the projected cost of establishing solar gardens. Finally, the Commission removed capacity limits and lower proposed compensation that would have severely hindered development.

In other words, it’s a promising year for community solar in Minnesota, and combined with the victory of solar over natural gas and the solar energy standard, Minnesota’s solar market is heating up.

Article by John Farrell, appearing courtesy Institute for Local Self-Reliance.

04/22/2014 1 comment

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