Advocates of the tariff say it is needed because solar-power developers need to be fairly certain that they can make money before investing in solar projects. In January, the Corporation Commission solicited input on a FIT from utilities and solar developers. The feed-in tariff, or FIT, would mirror similar rules in Germany, the world’s largest market for solar power.

The commission requires Arizona utilities to get 15 percent of their power from renewable sources like solar by 2025 and has been working with utilities to develop creative financing plans for renewable energy because it is more expensive than traditional power sources.

The tariffs require an electric utility to pay for the electricity and renewable-energy credits from solar facilities at an agreed-upon and sometimes predetermined rate for an extended number of years. California, Hawaii, Vermont, Maine, Oregon and five cities or utility territories in the U.S. use some form of FIT, according to the Corporation Commission’s research.

Like all utility costs, the expense of buying power through a FIT would be passed on to customers. The regulators are suggesting a limit on electricity bought through a FIT to cap the cost to ratepayers. The cost to an average household hasn’t been determined.

Arizona Public Service Co. has proposed two FIT programs using guidelines from the commission. APS proposes to offer a standard energy contract for small solar or other renewable projects, and a FIT for low-income housing, homeowners associations, apartments and non-profits. Those groups usually can’t take advantage of the standard financial incentives for going solar, but they could develop solar with a FIT.

Source: The Arizona Republic

For more information on this proceeding, visit the Arizona ACC eDocket site and search for Docket E-00000j-09-0505

On August 24, an administrative judge with the California Public Utilities Commission issued a proposal to expand what was once called the feed-in tariff program. It might still be called feed-in tariff by some, but it’s quite different from the kind of polices that have made Germany and other European countries hot solar markets.

Instead of setting solar electricity rates that utilities must use to buy power from independent project developers (European style), California’s proposal would require investor-owned utilities to hold two auctions per year and sign power purchase deals from developers with the lowest and most plausible bids.

While the 1-gigawatt proposal aims to lure more project developers, it also comes with complex pricing control mechanisms, said Adam Browning, executive director of Vote Solar Initiative, an advocacy group in San Francisco.

“This program is an elegant solution and provides a very compelling and workable model for generating whole sale distributed generation,” Browning said.

The new procurement process would apply to projects from 1-megawatt to 20-megawatt in size. It also would circumvent a sticky issue that showed up last month when the Federal Energy Regulatory Commission said states don’t have the authority to set wholesale electricity rates that would exceed “avoided costs.”

Utilities can buy power in order to avoid the expenses of building and operating their own plants. So the term “avoided costs” is often used to describe the prices utilities would spend to buy power, which in most cases comes from fossil fuel power plants that make up a big chunk of the electricity generation facilities in the country. In California, avoided costs refer to the prices for power from combined-cycle natural gas power plants.

The proposal would replace a feed-in tariff program that began in 2007 as a way to encourage water and wastewater treatment plant owners to install renewable energy projects and help utilities to meet a state mandate requiring them to have 20 percent of the electricity from renewable sources by 2010. Each project, which could use solar, wind, geothermal, among others, couldn’t be larger than 1.5 megawatts.

Enlarging the size of eligible projects to 20 megawatts each could make them cheaper to design and build them than the smaller projects. At the same time, proponents have reasoned, the project is not so big as to make it difficult to line up financing.

Source: Ucilia Wang, Gigaom

Note from the Editor

The Solar Panel Next Door

Sharing solar (or wind, or micro-hydro, etc…) is the hottest new trend in net metering.  It’s exciting to see so much progress within the last year alone, with more and more states jumping on the community renewables bandwagon.  This month Delaware added its name to the list with the enactment of SB 267. These policies present numerous advantages but perhaps most significantly, they expand benefits of renewable energy to a much larger pool of participants.  They also entail a lower cost of installation due to economies of scale and, with fewer constraints on system location, they can be sited more effectively to make better use of the resource. [Continued in Newsletter]

State News in Detail

Northeast States                       

Connecticut DPUC continuing meter aggregation work

New York PSC approves peak load provision for net metering, considers DG proposal for Massena          

Mid-Atlantic States       

Delaware enacts community net metering policy 

New Jersey removes 2MW cap for net metering; township asks the BPU for virtual net metering ability 

Midwestern States        

Indiana utility proposes an expansion of net metering and a FIT

Michigan PSC approves pilot electric vehicle rate for Detroit Edison

Missouri PSC seeks comments on geographic sourcing of renewables

Kansas KCC adopts net metering rules

Southern States                              

Texas universities launch innovative clean energy programs 

Western States                                               

Arizona’s Salt River Project plans to sell PV power to schools

CAISO proposes changes to large generator interconnection agreement

Idaho PUC approves system size cap change for Avista utilities  

Other States                     

Alaska enacts renewable energy goal

IREC News                                         

IREC releases 2009 Solar Market Trends Report 

Miscellaneous News    

FERC reaffirms its position on Feed-in Tariffs

NREL publishes Comprehensive Feed-in Tariff Guide for Policymakers

Utility energy storage test yields positive results

Upcoming Events        

Download the full newsletter as a PDF:  August 2010 Connecting to the Grid Newsletter

FORMAT

While customer-sited net metering and interconnection policies are primarily addressed at the state level, they are also becoming important on a regional basis. This newsletter has been designed to provide state-level policy updates and capture emerging regional trends. Connecting to the Grid is a free, electronic newsletter published each month by the Interstate Renewable Energy Council (IREC) and the North Carolina Solar Center at North Carolina State University. Click here to subscribe.

Editor: Laurel Varnado
NC Solar Center, NC State University

In June, the Public Service Commission, in a 3-2 vote, adopted rules that set the structure, operation and procedures for increasing the amount of electricity generated from renewable sources of energy and also to further diversify the energy portfolio of Missouri’s four regulated electric companies.  The rules were designed to carry out Proposition C, approved by Missouri voters in November of 2008.

The rules provided the procedures by which utilities are to meet the statutory obligations for renewable energy.  Missouri law requires that by 2011, electric companies must either generate or purchase at least 2 percent of the electricity they sell from renewable sources.  That percentage increases to approximately 15 percent by 2021.  The electric companies are required to meet those required percentages by either generating the electricity through the use of renewable energy sources or by purchasing renewable energy credits.  Under the rules, at least 2 percent of the renewable energy must be from solar.

In addition, the Commission determined that if a utility company needs to purchase renewable energy credits to meet rule requirements, the renewable energy associated with those credits must be sold to Missouri customers (known as geographic sourcing).

The Commission-adopted rules were sent to the Joint Committee on Administrative Rules (JCAR) which disallowed the language regarding geographic sourcing.  Therefore, uncertainty regarding that requirement remains.

The Commission is asking stakeholders to resume discussions in order to try and resolve the single issue of geographic sourcing through developing legislative proposals and regulatory options that will promote the development of renewable energy in Missouri while protecting retail customers.

Stakeholders, interested parties and the general public have been asked to submit initial written comments to the Public Service Commission by October 1, 2010.  Comments should reference the case number (EW-2011-0031).

While the KCC rules allude to the specifications in the 2009 Act, they do not actually outline any of these specifications. These rules outline a few provisions for interconnection but they are not substantive enough to warrant calling them interconnection procedures. In essence, they provide utilities with a wide range of discretion in applying interconnection terms to customers. It appears that utilities have a choice in requiring a utility external disconnect switch, installed at the customer’s expense. Overall, while it is a step forward that Kansas now has a ruleset in place, the interconnection provisions are largely regarded as a hindrance to customer-sited renewable energy.

Currently, customers owning projects up to a capacity of 25 kilowatts are eligible to receive credits for the generation they produce on solar, wind, biomass or hydropower projects. Avista has received commission approval to increase the size of projects that can qualify for the net metering rate to 100 kilowatts.

Customers who generate their own electricity can have their generation credited from their monthly billings. Those who produce more than they consume, can have their excess kilowatt-hours applied to future billing periods to reduce their bills. At the end of the calendar year, any unused kilowatt-hour credits are granted to the company without compensation to the customer-generator.

Avista allows customers to enroll as net metering customers on a first-come, first-served basis until the cumulative generating capacity of all customers equals 1.52 megawatts or about 0.1 percent of Avista’s retail peak demand.

Currently, Avista, which serves about 120,000 electric customers in northern Idaho, has only 14 Idaho net metering customers with a collective generation capacity of 37 kilowatts, far below the 1.52 MW cap. Avista said it has been approached by at least one residential customer and one commercial customer asking that the 25 kW limit be expanded to 100 kW.

A full text of the commission’s order, along with other documents related to this case, is available on the commission’s Web site. Click on the electric icon, then on “Open Electric Cases” and scroll down to Case Number AVU-E-10-2.

Source: Idaho PUC press release

Power Factor Design and Reactive Power Capabilities

Reactive power is supplied to the transmission system from a variety of sources, mainly conventional generators, and it is essential for transmitting power and maintaining voltage stability on the transmission system. CAISO’s current LGIA requires wind generators to operate at a power factor within a 0.95 leading to 0.95 lagging if the operational requirement was shown by interconnection studies to be necessary to maintain safety and reliability. The proposed changes will require all asynchronous generators to achieve a power factor range of 0.95 leading and 0.95 lagging without exceeding the ratings of any equipment. Facilities may meet this requirement by using equipment designed to supply reactive power, fixed or switched capacitors, or a combination of the two. CAISO has also reserved the ability to curtail asynchronous generators to the extent needed to achieve the designated power factor range. Historically, the requirement to supply reactive power had been seen by FERC as a significant added cost to wind generators but not for conventional generators. However, CAISO’s expert testimony claims that the cost of compliance will likely be in the range of 0.25% to 1% of the total plant cost.

Voltage Regulation and Reactive Control Requirements

CAISO’s current LGIA requires each generating unit to maintain a voltage schedule by operating the generator to produce or absorb reactive power within design limitations. CAISO proposes to require asynchronous generators to use an automatic system to control reactive power capability that has both a voltage regulation and net power factor regulation operation mode. Voltage deviations outside of a voltage band (+/- 0.02 per unit of the nominal voltage schedule set by the Transmission Owner or CAISO) may not exceed five minutes duration per incident, except where there is insufficient reactive capacity to maintain a voltage schedule within the band. Furthermore, interconnection customers will not be allowed to disable voltage regulation controls, without specific permission from CAISO, when a facility is operating at a level greater than 20% of its capability.

Low-Voltage and Frequency Ride-Through

Low-voltage and frequency ride-through defines a generating facility’s ability to stay interconnected to and synchronized with the transmission system during disturbances. The frequency of the transmission system is adversely affected when generators trip offline. Wind generators are already required to have ride-through capabilities but, according to CAISO, asynchronous generators have been allowed or encouraged to trip offline in response to a grid disturbance. CAISO’s proposal clarifies that the ride-through requirements will apply to all asynchronous generating facilities, and clarifies that such facilities will be required to remain in continuous connection with the transmission grid (although not necessarily injecting current) through voltage recovery after single-phase faults with delayed clearing. In addition, asynchronous generators will be required to ride through all types of normally cleared faults, including severe three-phased faults. CAISO did clarify, however, that the ride-through requirements do not apply to multiple-fault events. For solar facilities, the main technical issue will be whether their balance of plant systems, e.g., cooling systems, will not trip off or can restart following a ride-through event. CAISO believes these requirements will provide better protection against the possibility of losing generation during a transmission system disruption, and that the costs of compliance does not concern generation developers (even those with power purchase agreements already in place).

Generator Power Management Requirements

CAISO proposes to revise its power management requirements in order to ensure that the transmission system remains reliable as conventional generators are replaced by variable energy resources. First, asynchronous generators must have Supervisory Control and Data Acquisitions (SCADA) communications links with CAISO, and have the ability to limit active power output to between minimum and maximum operating limits (in increments of 5 MW or less) in response to a dispatch instruction or operating order. Eligible intermittent resources will only be held to a maximum output limit; they will not be required to operate below levels that cannot be supported by the available energy source. Asynchronous generators must also have the ability to respond to automated dispatch system instructions.

Second, asynchronous generators will also be required to have the installed capability to limit power change ramps, with the exception of downward ramps due to a loss of energy resource for eligible intermittent resources. Asynchronous generators must be capable of limiting their ramp rates to 5%, 10%, and 20% of the facility’s maximum capacity per minute. Generators may implement the ramping limit by using stepped increments with individual increments being 5 MW or less. CAISO does not intend to enforce ramp rate limitations continuously; rather, ramp rate limitations will apply when a resource’s natural ramp rate could threaten transmission grid reliability.

Third, CAISO proposes to require all asynchronous generators to have the installed capability to reduce output in response to an over-frequency event. When the frequency response control is enabled by CAISO, the control must continuously monitor system frequency and reduce output in response to system conditions. Asynchronous generators will not, however, be required to adjust output in response to an under-frequency condition, as that would require facilities that cannot control their fuel supply to increase output upon demand. CAISO proposes that its power management requirements be made effective as of January 1, 2012 in order to give asynchronous generators a reasonable time to comply.

Exemptions from New Requirements

CAISO is proposing exceptions to the proposed operational requirements in order to minimize the impacts on financial commitments made by interconnection customers.

• Interconnection customers that can demonstrate a binding commitment made as of May 18, 2010 to purchase inverters for 30% or more of the facility’s maximum generating capacity will be exempt from the new low-voltage ride-through requirements, if the inverters are incapable of complying with the requirements.
• For customers that, as of May 18, 2010, purchased equipment that is not compliant with the new power management criteria, CAISO will develop operational standards that are consistent with the capabilities of the purchased control equipment and submit such standards to FERC for approval in a non-conforming LGIA.

 Source: Stoel Rives LLP

SB 267: Strengthens Delaware’s net metering law by increasing the amount of energy customers can sell back to their electric supply grid. Homes and businesses may sell back 110 percent of their aggregate consumption to the grid. Also, customers, such as a business campus or agricultural operations can aggregate several meters for multiple locations to determine how much power can be sold back through one meter. In this way, customers will be able to finance larger renewable energy installations to meet their needs. Finally, homeowner associations and similar groups of customers sharing a unique set of interests will be able to cooperatively finance and build community-scale renewable energy projects both on and off-site.

SB 1 for SB 119: Extends and expands Delaware’s Renewable Portfolio Standard (RPS) so that 25 percent of Delaware’s electricity must come from renewable energy sources by the year 2025; includes solar energy targets; and provides incentives for local labor and manufacture of renewable energy systems. For the first time, the Delaware Electric Cooperative and municipal electric companies will be included in the standard through the new statute or through their own plan meeting comparable results. This is significant since these entities provide about a third of Delaware’s electricity. The act also provides consumer protections by limiting any rate impacts.

SB 266: Updates the Green Energy Fund law to address the large backlog of projects across the state currently awaiting incentive funds. Gives the DNREC secretary the ability to direct more of the Green Energy fund to clear the existing backlog and focuses on incentives that will maximize economic development benefits. It allows for a gradual transition from the over-reliance on the fund for financing renewable energy systems and balances the program’s resources with current and expected demands.

SB 316. Makes it possible for property owners to install and use ground-mounted solar energy systems on land zoned residential where the lots are one-half acre or greater in size without being restricted by the use of covenants, restrictions, and conditions in deeds, contracts and other legal instruments which might seek to prohibit or unreasonably restrict such construction.

 The clean energy bills will facilitate the potential installation of approximately 250 megawatts of new solar photovoltaic systems (enough to power approximately 62,000 homes) by 2025, resulting in the creation of hundreds of secure, quality jobs. These bills will also promote other sources of renewable energy, like offshore wind infrastructure or a large wind park off the coast of Delaware, which will create potentially thousands of jobs in manufacturing, metal fabricating, electrical services and marine trades.

Source: Governor’s Press Release

Through June 23, 2010, the CSI Program had received 764 megawatts of applications for over 42,000 new solar projects. The goal of the CSI Program is to install 1,750 megawatts of solar energy systems by 2016. Due to unexpected participation rates and mistaken assumptions about the types of incentives applied for, the CPUC is concerned that the CSI budget could be depleted before the CSI achieves its megawatt goals.

To combat budget exhaustion, CPUC is considering three main incentive system modifications. First, CPUC may adjust or remove the discount rate built into the PBI incentive payments. Second, and most significantly for public agencies, the CPUC may establish a higher rebate level for tax-exempt entities such as government and non-profit institutions. Due to considerable decreases in the cost of solar equipment in the last few years, an increase in the CSI incentive level available to public agencies could have a significant impact on the overall cost of solar projects for public agencies. Third, the CPUC ruling issued proposes to shift $20 million in program administrative funds to the incentive budget. This would increase the total amount of incentives available from $1,707,000 to $1,727,000.

A copy of the CPUC Ruling is available by clicking here.  

Source: Best Best & Krieger LLP, Sophie A. Akins

NIPSCO filed a request on July 19 to expand net metering and allow the utility to purchase electricity generated by customers’ renewable energy projects through a feed-in tariff rate.

The state’s current net metering limit is 10 kilowatts and is available only to residential customers and K-12 schools. The proposal would expand the rated capacity to 100 kilowatts and allow all customers to participate, including businesses.

NIPSCO’s net-metering program allows customers to connect to the grid and get credit for solar, wind and hydro energy they generate. The utility pays customers the amount that NIPSCO charges for electricity — 11 cents per kilowatt hour. Currently, 21 customers participate in the program.

If approved by the Indiana Utility Regulatory Commission, the proposal would also start a pilot program known as the Renewable Feed-In Electric Rate, which allows customers to connect generation sources up to 5 megawatts in capacity and sell the power to NIPSCO. The program would last through the end of 2013.

How much customers would be paid depends on the type of energy and (for wind) the capacity of the project. Solar power would pay 26 cents per kilowatt hour, wind units smaller than 100 kilowatt hours 17 cents, wind units between 100 kilowatt hours and 5 megawatts 10 cents, and biomass 7 cents. Customers would receive a check from NIPSCO.

The utility has capped the net metering proposal at 6 megawatts and the feed-in program at 30 megawatts. NIPSCO said if the cap is reached, total renewable energy generation would generate enough electricity for 10,000 homes for a year.

NIPSCO expects the IURC to rule on the request in the coming months, but did not have a more specific timeline.
Source: Gary Post Tribune article