Every year we celebrate and encourage exceptional solar and renewable leadership by giving Solar Champion Awards.  Our 2012 winners are…drumroll, please…:

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Today, more action in the on-going saga of FERC and feed-in tariffs. The brief backstory goes like this: The California Public Utilities Commission, in response to a state law, proposed a feed-in tariff for combined heat and power (CHP) systems. Anticipating legal action from utilities, the CPUC filed a Petition for Declaratory Order asking for input from FERC, parties (including Vote Solar) intervened asking for more flexibility, the FERC issued a decision, then the CPUC filed again asking for further clarification, at which point the FERC totally reversed itself with a new decision.  Then the utilities requested rehearing, which is still pending.  In the iterim, the CPUC–relying on the latest FERC decision–went forward with the implementation of the original CHP FIT in a decision approved on December 16, 2010. » Read the rest of this entry «

In this business, nothing comes easy.  In the wake of FERC’s blockbuster ruling of October 21 changing course on feed-in tariffs, the California investor-owned utilities and the Edison Electric Institute have appealed, asking for re-hearing or re-consideration, or rejection of portions.

Their rationale?  Essentially, they disagree with the legality of the change, but also have procedural concerns.  From EEI’s filing: » Read the rest of this entry «

On Friday, Dec 3, 2:30 -4:30 EST, FERC staff will hold the first of a series of webinars for the environmental/NGO community, seeking to explain what FERC does and discussing some of the Commission’s policy initiatives related to integrating clean energy resources into the grid.  The first webinar will provide an overview of FERC’s jurisdiction under the Federal Power Act and some of the Commission’s key orders affecting wholesale electricity markets and grid planning (including how the orders can affect energy efficiency and renewable energy integration).  Subsequent webinars will focus on specific FERC initiatives now underway that have significant environmental implications. » Read the rest of this entry «

On July 15th, the interstate electricity regulators at the Federal Energy Regulatory Commission (FERC) issued a ruling with ramifications for feed-in tariffs in the United States. In an Aug 4 article for Greentech Media, Vote Solar’s Adam Browning discussed options for designing state wholesale DG solar programs that comply with the FERC ruling. We have reprinted the text below.

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A feed-in tariff, in its common form, is a requirement for utilities to buy wholesale electricity under a fixed-price contract. That’s electricity delivered to the grid for resale to other utility customers, as opposed to retail electricity that is used on-site; this approach lowers the consumer’s utility bill through mechanisms like net metering. This market mechanism is popular in Europe; FERC’s recent ruling provides clarity regarding just what states can and can’t do when it comes to feed-in tariffs here in the U.S.

The history behind FERC’s recent decision starts in 2007, when the California Legislature passed AB 1613, which established a feed-in tariff program for small combined heat and power systems in the state.  As the California Public Utilities Commission began implementing the new law, some investor owned utilities objected on the basis that the state does not have the jurisdiction to mandate this kind of program.  Their argument: the Federal Power Act gives FERC exclusive authority over wholesale electricity sales in interstate commerce, and states are pre-empted from setting wholesale power rates that exceed utility avoided cost.  This is not a new issue — energy practitioners have been confronting it for a long time.

The CPUC then petitioned FERC for a Declaratory Order to clarify the subject, and the utilities responded with a petition of their own.  Multiple organizations, including the Interstate Renewable Energy Council, SEIA, CalSEIA, the Solar Alliance and Vote Solar, intervened with arguments for more flexibility.

The decision? From the summary:

“FERC affirmed in its order that its authority under the FPA includes the exclusive jurisdiction to regulate the rates, terms and conditions of sales for resale of electric energy in interstate commerce by public utilities. FERC also explained that the role of States in setting wholesale rates is limited to determining “avoided cost” rates for qualifying facilities pursuant to PURPA.

FERC thus found that the CPUC’s decision under AB 1613, including the CPUC-set price, would be consistent with these federal laws as long as it satisfies certain requirements:

●     The CHP generators must be QFs pursuant to PURPA.

●     The CPUC-set price must not exceed the avoided cost of the purchasing utility.”

In other words, state legislatures and regulators are restricted in their ability to mandate premium, fixed-price requirements.

What does this mean going forward? While this decision clearly limits feed-in tariff options, it does not preclude effective wholesale distributed generation programs. When the issue came up in a recent, similar proceeding — the CPUC’s effort to expand the renewable feed-in tariff program under AB 1969 (R.08-08-009) — parties were required to file legal briefs on this subject. Here are a few policy approaches that fall within state’s price-setting authority:

●     Set the feed-in tariff price at utilities’ avoided cost

●     Establish a more targeted requirement (e.g., solar PV systems from 1MW to 10 MW) and let the market set the price

●     Set a price at avoided cost, and cover the marginal gap to a workable price with a tax benefit or renewable energy credit from a public benefit fund.

There are a few real-world examples of feed-in tariffs that use this approach.  The Sacramento Municipal Utilities District recently issued a feed-in tariff priced on their time-differentiated avoided cost of generation (modeled on expected PV output, it comes out to a levelized rate of about 14 cents per kWh).  All 100 MW of the available contract capacity was immediately sold out, principally in 5 MW chunks (note that similar programs eligible for only smaller sytems have proven less effective).

Another take on this approach comes from California’s SB 32. Passed in 2009, it is a fixed-price feed-in tariff that attempts to raise the ‘avoided cost’ by capturing as much value associated with distributed generation as possible (avoided transmission and distribution upgrades, etc.).

The downside to using the avoided cost approach, of course, is that these costs can vary widely, are the subject of much contention, and there is no guarantee that the final price will be sufficient to deploy renewables.

Which brings us to another option: mandate the desired outcome, and let the market set the price.  The CPUC has proposed a 1 GW pilot program, called the ‘reverse auction mechanism’ (RAM), which elegantly deals with the problem by guaranteeing a market instead of guaranteeing a price.  Utilities would be required to do multiple annual solicitations for systems from 1MW to 10 MW in size, and the best price wins.  All parties to the proceeding seem to agree that this approach is jurisdictionally compliant.  We are currently waiting on the Administrative Law Judge assigned to the matter to issue his proposed decision.

We have some real-world examples of logic behind this market approach. For the past several years, Southern California Edison has had a voluntary Renewable Standard Offer program, consisting of a fixed-price offer to buy renewable energy from systems under 20 MW in size, with the price set at the Market Price Referent (‘MPR’ is calculated annually by the CPUC; it’s the 20-year levelized cost of energy of a combined-cycle natural gas plant, meant to represent the next marginal unit of generation).  In 2009, SCE contracted for 140 MW of PV.  It’s a great story — here are significant amounts of solar purchased below the cost of fossil fuels.

The big question, though, is whether this pricing will work in the future. Natural gas prices have plummeted, and the MPR went down about 20% this year.  Is the new ‘avoided cost’ price enough to deploy solar?  This could pose a significant problem.

To address this concern, SCE recently announced that it will change its pricing approach going forward.  Instead of pricing solar based on the cost of natural gas, they will price solar based on the cost of solar as bid.  In order to make sure that the bids are viable and not aspirational phantom projects, the program requires development security of $20/kW and project development timelines.  To reduce parasitic transactional costs and help developers line-up financing ahead of time, the program uses standard, non-negotiable contracts.  In order to drive projects that can come on-line quickly and don’t need new transmission, this policy is only applicable to projects under 20 MW.  (Note that SCE also has a similar program for rooftop PV systems that are 1MW to 2 MW in size.  On July 27, it released the results of the first solicitation: 60 MW of projects throughout its service territory.)

This market-based approach is FERC-compliant, captures the latest in solar’s cost reductions and delivers that value to ratepayers, and helps drive down solar’s costs by sending helpful market signals throughout the solar value chain. Think of it as the next generation of the feed-in tariff: FIT 2.0.

So, even though the FERC decision clearly restricts states’ feed-in tariff authority, it is important to recognize that there are still ways of designing successful programs for procuring wholesale distributed generation.

FERC may have recently put the kibosh on states implementing European-style Feed-in Tariffs for the moment, but that doesn’t mean the U.S. is left high and dry without ways to drive wholesale solar markets. We’re seeing daily action from utility PV programs that play by FERC’s rules.

Just today, Southern California Edison announced 60 MW worth of contracts under its new wholesale distributed generation (WDG) program. These winning bids will be installed on 31 rooftops and five ground-mounted sites across SCE’s service territory and deliver clean, reliable, wholesale power to the grid (as opposed to meeting on-site load).This is the first traunch of contracts for the utility’s 500 MW distributed solar program – half of which the utility will own and half of which must be contracted like this through independent producers.

As you may recall, SCE proposed the program as a mechanism for meeting its RPS requirements. The RPS may have set the end-goal of 20% by 2010 (with efforts still underway to increase to 33% by 2020), but it was the utility that opted to develop distributed solar to meet part of that requirement – a departure from the previously exclusive focus on large-scale projects in the 10 – 500 MW range. SCE’s move into WDG is significant for a few reasons:

1. It was a clear example of utilities recognizing the value of power being generated within the distribution network – a solid case for developing more rooftop solar.
2. It opened up a new type of solar development – adding to a nice robust wholesale policy framework that supports diverse market participation (large-scale and distributed systems, utility-ownership and independent industry alike). That’s in addition to the state’s retail program that encourages customers meet their own electricity needs with solar (CSI plus net metering). We think all that diversity of opportunity’s a good thing for building a resilient solar market and lowering solar costs for everyone.
3. The program used a competitive solicitation process rather than a fixed standard contract offer – a policy approach designed to ensure projects get built at the best cost to ratepayers. Today’s announcement validates the competitive auction mechanism that we’re also seeing arise in the utility’s RPS procurement more broadly and in the CPUC’s to-be-launched twist on the Feed-in Tariff (because the incentive model doesn’t set a wholesale price, it’s another innovative way states can support wholesale solar development without stepping on FERC’s jurisdictional toes).

Northern California’s PG&E has a similar program in the works, so expect to see more WDG on the way.

On Monday, I gave a presentation at the NARUC summer meeting in Sacramento.  For energy wonks, it’s kind of like getting invited to the all-star game.

I was invited to speak on the panel “Feed-in Tariffs and other Tariff Designs as the Tools for Ramping Up Renewable Resource Development.”  The invite came based on presentations we’ve given and work we have done on the subject before the California Public Utilities Commission, the Arizona Corporation Commission, and the Nevada Public Utilities Commission – bodies that regulate the electric utilities in their respective states.

If you will forgive the self-serving aside, Commissioner Wagner of Nevada introduced the segment by saying “Colleagues, if Vote Solar is not working in your jurisdiction, you should ask them to come.  They provided timely and accurate data, analysis and policy expertise, and were instrumental in helping us with our renewable energy agenda.”  Or words to that effect. The validation of Jim and Annie’s work last year was much appreciated, especially since NV was one of the very few wins in a brutal year for solar.  Let me return the favor by celebrating Commissioner Wagner as a fierce and effective champion for renewable energy and NV ratepayers.

Here’s the presentation (4 MB ppt).  It’s much better with the soundtrack, but in short, given the national nature of the audience, the goal was to:

1. Make the case that solar deserves consideration as a scalable resource, especially as it is now much cheaper than many believe
2. Clarify that there are two markets: retail and wholesale, each with their own benefits from both the customer and regulatory perspective, and therefore each deserving of their own separate policy support
3. Identify the series of decisions that have to be made when designing successful wholesale distributed generation markets (ie: small-to-mid size solar energy systems delivering power to utilities for resale)
4. Walk through the range of policy solutions to effectively drive solar growth given those considerations
5. Briefly discuss the approaches taken by different existing programs across the U.S., and the lessons that should be drawn from the results

This discussion is especially pertinent given the recent FERC decision, which defined the federal vs state jurisdiction over price-setting in Feed-in Tariff type incentive programs.  California and Arizona are pioneering approaches to successful wholesale distributed generation that meet key criteria for sustainable solar market growth:

1. Legal (ie: jursidictionally compliant with the Federal Power act – see FERC decision above)
2. Scalable (ie: are achievable at politically palatable price points)
3. Provide the flexibility and responsiveness to expand the market as price reduces
4. Build strong installer capacity by providing continual market opportunity and avoiding boom-bust cycles

There is a lot more work to be done, but these initial efforts in are on track to bring gigawatts of wholsale distributed solar generation online as we speak.

We’ll put together a webinar on this shortly.

- Adam

On Thursday, the Federal Energy Regulatory Commission (FERC) issued a decision with ramifications for feed-in tariffs in the United States.

Here’s the history.  The California Legislature passed AB 1613, which established a feed-in tariff program for small combined heat and power systems in the state.  As the California Public Utilities Commission implemented it, some investor owned utilities objected on the basis that the state does not have jurisdiction.  Their argument: the Federal Power Act gives FERC exclusive authority over wholesale sales in interstate commerce, and states are pre-empted from setting wholesale power rates that exceed utility avoided cost.  This is essentially the same issue that was raised in the CPUC’s administrative proceeding to expand the feed-in tariff program under AB 1969, as described here (more background here).

The CPUC then petitioned FERC for a Declaratory Order on the subject, and the utilities responded with a petition of their own.  Multiple organizations, including VSI, intervened with arguments for more flexibility (if you want all the docs, click here and enter EL10-64 as the docket number).

The decision?  Here’s a link–wonks should really read the whole thing.  From the summary:

“FERC affirmed in its order that its authority under the FPA includes the exclusive jurisdiction to regulate the rates, terms and conditions of sales for resale of electric energy in interstate commerce by public utilities.FERC also explained that the role of States in setting wholesale rates is limited to determining “avoided cost” rates for qualifying facilities pursuant to PURPA.

FERC thus found that the CPUC’s decision under AB 1613, including the CPUC-set price, would be consistent with these federal laws as long as it satisfies certain requirements:

• The CHP generators must be QFs pursuant to PURPA.
• The CPUC-set price must not exceed the avoided cost of the purchasing utility.”

What does this mean?

The decision essentially reaffirms the approaches described in the linked Grist article.  The options are:

-Set a price at utilities’ avoided cost
-Establish a more targeted requirement (say, PV systems from 1-10 MW) and let the market set the price
-Set a price at avoided cost, and cover the marginal gap to a workable price with tax or REC from a public benefit fund.

In California, SB 32 addresses the issue by trying to raise the ‘avoided cost’ by capturing as much value associated with DG as possible (avoided T+D, etc).  This was the approach we originally took in the CA FiT proceeding (R.08-08-009).  The downside is that there is no guarantee that the final price will be sufficient to deploy renewables.

Another option is to fine-tune the desired outcome, and let the market set the price.  The CPUC has proposed a 1 GW pilot program, called the ‘reverse auction mechanism’, or ‘RAM’, which elegantly deals with the problem by guaranteeing a market instead of guaranteeing a price.  Utilities would be required to do multiple annual solicitations for systems 1-10 MW in size, and best price wins.  Even SCE agrees this is jurisdictionally compliant.   We are still waiting on the Administrative Law Judge assigned to the matter to issue his proposed decision.

In short, while the FERC decision restricts state flexibility, there are ways of designing successful programs for procuring wholesale distributed generation.