FERC Adds Another Standard for DG Interconnection

The Federal Energy Regulatory Commission (FERC) has adopted standard rules for interconnecting distributed generation (DG) projects of 20 MW or less with the electricity grid. These new rules will operate alongside FERC's previously issued rules that govern interconnections of DG projects larger than 20 MW. FERC also has an ongoing proceeding that is developing special rules for interconnecting wind energy projects with the grid [see FERC's Generation Interconnection web site].

In most cases, FERC's new rules will cover DG projects that are interconnecting with the grid at the transmission level. However, FERC asserts that if the DG project plans to interconnect with a portion of the distribution system subject to an open access transmission tariff (OATT), for the purpose of making wholesale sales, then this final rule would apply.

The new rule (FERC Order No. 2006) directs public utilities to amend their OATTs to offer non-discriminatory, standardized interconnection service for small generators. The amendments must include a Small Generator Interconnection Procedures (SGIP) document and a Small Generator Interconnection Agreement (SGIA).

The SGIP contains the technical procedures that the small generator and utility must follow in the course of connecting the generator with the utility's lines. It provides three ways to evaluate a request for interconnection. There is a default study process that can be used by any project and two procedures that use technical screens to evaluate proposed interconnections: (1) the fast track process for a certified facility no larger than 2 MW and (2) the expedited process for a certified inverter-based project no larger than 10 kW.

The SGIA contains the contractual provisions for the interconnection and spells out who pays for improvements to the utility's electric system, if needed to complete the interconnection. Issues such as insurance requirements, dispute resolution procedures and liability related items are also addressed.

The final rule titled, Standardization of Small Generator Interconnection Agreements and Procedures, is effective 60 days after its publication in the Federal Register. Regional transmission organizations (RTOs) and independent system operators (ISOs) have an additional 90 days to comply.

While the federal rules are generally welcomed by the distributed generation industry, action at the state level may be more meaningful and more helpful to the emerging industry. Interconnection of most DG projects under 20 MW will be taking place at the distribution system level and will not be subject to the requirements under Order 2006. FERC acknowledges this and says, "...our hope is that states may find this rule helpful in formulating their own interconnection rules.

More

Washington Laws Encourages Locally Manufactured DG Equipment

Two proposals unanimously passed by the legislature and signed into law earlier this month by Washington's Governor, Christine Gregoire, should put distributed generation and renewable energy on the fast track in the state. The first bill (SB 5101) establishes a renewable energy production incentive that is larger if the equipment comes from in-state manufacturers. The second bill (SB 5111) provides corporate tax breaks for solar energy businesses in the state based on their sales.

Under the new law, homes and businesses with renewable, on-site power systems will earn a credit of 15 cents per kilowatt-hour (kWh) with a cap of $2,000 annually per household. The bill contains multipliers that increase or decrease the credit amount if components of the solar, wind or anaerobic digester are manufactured in Washington. For example, a photovoltaic project that uses solar modules and an inverter manufactured in Washington state would be eligible for a 54 cents/kWh payment. The program begins July 1, 2005 and sunsets on June 30, 2014.

The second bill (SB 5111) provides a tax credit to solar energy companies as a way to encourage photovoltaic and related equipment manufacturing in the state of Washington.

The solar manufacturing tax credit allowed in the new law is roughly one-third of one percent of the value of the solar energy systems that are sold. The tax credit program ends June 30, 2014 and applies to firms meeting the criteria after October 1, 2005.

More

Minnesota Passes 20 Percent Ethanol Mandate

On May 10th, Minnesota's Governor signed a bill into law that could result in a requirement that the state's gasoline supplies contain 20 percent ethanol (E-20). If the rules go into effect, it would double the current 10 percent ethanol blends that are now standard throughout the state.

Under the legislation, a new E-20 mandate would take effect in 2013 unless ethanol has already replaced 20 percent of the state's motor vehicle fuel by 2010. The rule would expire at the end of 2010 if Minnesota is not granted federal approval to use E-20 gasoline blends.

Professor Bruce Jones, Minnesota Center for Automotive Research at Minnesota State University, Mankato, reported on a study the university conducted on 15 vehicles comparing the burning of E-10 gasoline to E-30 (a higher ethanol level than proposed). No driveability or material compatible problems were experienced during the study, and all emissions were low and well below federal standards.

Minnesota has North America's largest network of E-85 (85% ethanol blend) gas stations with approximately 130 stations now available to consumers. Minnesota was the first state to require the use of ethanol in gasoline. Other states are beginning to follow suit. Last year Hawaii enacted a measure similar to Minnesota's mandate. The Governor of Montana signed their new E-10 requirement into law this past Friday.

The ethanol industry provides jobs for more than 5,300 Minnesotans and pumps $1.3 billion dollars into Minnesota's economy. There are 14 ethanol plants in Minnesota that produce more than 450 million gallons of ethanol every year, with two more plants currently under construction. Minnesota ranks 4th in the nation in production of fuel-grade ethanol, after Iowa, Illinois and Nebraska. Minnesota corn growers send approximately 15% of their crop to ethanol plants.

We here at Democratic Energy are supportive of the development of a transportation fuels sector based on biofuels from renewable resources. We find the development of the ethanol industry in Minnesota particularly interesting since it is widely based on farmer-owned facilities. However, we feel that a better policy approach would have been to enact a broad renewable fuels standard rather than the more prescriptive approach of mandating ethanol. A renewable fuels standard, for example, would include ethanol, biodiesel, electricity from renewable energy sources, and even hydrogen derived from renewable resources. Certainly in the near term in Minnesota, a renewable fuels standard would still be satisfied by ethanol but there wasn't a need to limit the scope of the new rules to ethanol alone.

More

An Assessment of Solar Power on Rooftops

In March 2005, the Energy Foundation released a study prepared for them by Navigant Consulting and Clean Energy Research. The study was completed in September 2004 and claims to be the first of its kind to do an assessement and estimate of the rooftop solar photovoltaic market potential on a state-by-state basis.

We here at Democratic Energy applaud the nicely done section of the report that calculates the square footage of residential and commercial rooftops that could be available for solar installations for each state. The author's produced detailed tables that will make it much easier to calculate the possibilities that photovoltaics can provide in different areas of the country.

The authors make some well considered yet aggressive assumptions for their analysis. The efficiency gains and cost reductions projected by the study are ambitious and depend on many factors coming together to bring about the rosy conclusions of gigawatts of annual PV market penetration after 2010.

1. The study assumes that the power density of generating electricity from solar cells increases from 8.7 watts per sq. ft. in 2003 to 10.2 W/sq. ft. in 2010 and 12.3 W/sq. ft. in 2025.

2. The study assumes that 65 percent of commercial roof space could be used for solar installations and that 22 percent of roof space for residential applications (including flat-roofed apartments) could be used for solar installations.

3. The study's breakthough PV costs of $2.00-$2.50/Watt (installed) by 2010, represents a 53 percent reduction from the business as usual scenario (Note: We here at Democratic Energy feel that the 3 percent annual cost reduction of the business as usual scenario is also an agressive assumption). The author's say, "We [Navigant] emphasize that these cost reductions can only be achieved with strong, continued government support in the near term that creates a positive investment climate for private investors."

4. The study calculates that 6 percent of the overall market potential would be developed by 2025.

Calculations from the study show that in 2010:

- At $2.00-2.50 per installed watt, the annual market potential for grid-connected residential and commercial building PV applications is estimated at 2,900 MW, representing an annual market of about $6.6 billion (equipment and installations).

- Rooftop space is not a constraining factor for solar development. Residential and commercial rooftop space in the U.S. could accommodate up to 710,000 MW of solar electric power (if all rooftops were fully utilized, taking into account proper orientation of buildings, shading from trees, HVAC equipment, and other solar access factors). For comparison, total electricity-generating capacity in the U.S. today is about 950,000 MW.

- The Pacific and Mid-Atlantic regions together would account for 52% of the potential residential and commercial sector demand.

- California alone has the potential for about 40% of the total building rooftop market potential—through a combination of favorable sunlight levels and high retail energy prices.

More