AN ACT CONCERNING SOLAR POWER.

This bill requires the Renewable Energy Investments Board, which manages the Clean Energy Fund, to establish a residential solar photovoltaic (PV) incentive program and sets the rules for this program. It requires that this program result in at least 30 megawatts (MW) of new residential solar PV installations by December 31, 2021 (a megawatt is the amount of power used by 750 to 1,000 homes). The design of the program is subject to Department of Public Utility Control (DPUC) approval. The bill requires that the program be funded by the existing renewable energy surcharge on electric bills, plus available federal funding. No more than one-third of the money going into the Clean Energy Fund can be used for this program.

The bill requires the Clean Energy Fund and the Conservation and Load Management Fund to develop coordinated programs to create a self-sustaining market for solar thermal systems for electric, natural gas, and fuel oil customers.

The bill requires the Clean Energy Fund to provide an additional incentive of up to 5% of the incentives provided under the residential PV and solar thermal programs for using major system components manufactured or assembled in Connecticut. The fund must provide an additional incentive of up to 5% if the major components are manufactured or assembled in a distressed municipality or a targeted investment community.

The bill requires the electric companies to seek to enter into long-term contracts to buy the power produced by nonresidential PV projects located on the customer's premises. The companies must seek contracts from medium and large nonresidential PV systems. All contracts are subject to DPUC approval. The bill entitles the medium-sized systems to a price equal to the highest accepted bid price in the most recent large system solicitation, plus an additional incentive of up to 10%.

The bill requires each electric company to file with DPUC, for its approval, a tariff for production-based payments to owners or operators of utility-scale solar projects. The tariff must provide for payments to up to 50 MW of generating capacity. The electric companies can build and operate up to one-third of this capacity under certain circumstances. The nonresidential and utility-scale PV programs are funded from electric rates.

The bill requires the Clean Energy Fund, in consultation with the Office of Policy and Management (OPM) and the Department of Public Works (DPW), to conduct a feasibility study by July 1, 2010, of placing PV systems on certain state facilities. It requires OPM, in consultation with the fund, to issue one or more requests for proposals for the deployment of these systems on these facilities.

The bill requires the Renewable Energy Investments Board to identify barriers to the development of a permanent Connecticut-based solar workforce. The board must provide for comprehensive training, accreditation, and certification programs through institutions and individuals accredited and certified to national standards.

The bill caps the total cost of all of the programs and specifies the steps that DPUC must take if it projects that the cap will be exceeded.

By law, electric companies must file with DPUC, for its approval, long-term power purchase contracts with certain renewable energy generators for 150 megawatts of power (Project 150). The bill delays a deadline for companies to make this filing and expands the requirement to reflect attrition in project development after contracts are signed. It requires DPUC to study the operation of the contracts and report its findings and recommendations to the Energy and Technology Committee by September, 1, 2011. DPUC must do so in consultation with the Office of Consumer Counsel and the Renewable Energy Investment Board.

*House Amendment “A” makes many changes in the underlying bill. It adds the (1) funding caps for the solar programs, (2) bonuses for Connecticut built systems, and (3) provisions on Project 150. It reduces the size of the residential PV program and modifies the nonresidential program. It eliminates provisions that (1) authorized $ 150 million in bonding for placing PV systems on state buildings and (2) allowed “net metering” customers that are local governments or educational, religious, or nonprofit organizations and that generate power from renewable resources to transfer the billing credit they receive for this power to related customers.

Under the bill, the board must offer direct incentives for the purchase or lease of qualifying residential PV systems. Under the bill, residential buildings are those that have one to four units. The incentive can be paid out on either a per kilowatt-hour basis or as a one-time upfront incentive based on expected system performance. The board must consider (1) verified solar system characteristics, such as operational efficiency, size, location, shading, and orientation, when determining the type of incentive and (2) willingness-to-pay studies.

By law, the board must develop a biennial comprehensive plan. Under the bill, starting with the FY 10 to FY 12 plan, the board must develop a proposed schedule in each plan for offering the incentives over the duration of the program. The schedule must (1) provide “blocks” that result in a total of 30 MW of residential PV capacity and projected incentive levels for each block; (2) provide incentives that decline over time to help foster the development of a state-based solar industry; (3) automatically move to the next block once the fund has committed the resources for a block; and (4) provide comparable incentives to buy or lease qualifying systems. The board may retain a consultant with expertise in solar energy program design to help develop the incentive schedules. DPUC must review and approve the schedule. The board can modify the approved schedule before it issues its next plan to account for changes in state or federal law or developments in the solar market when these changes could affect the expected return on investment of a typical residential PV system by 20% or more.

The board must establish and periodically update program guidelines, including (1) eligibility criteria, (2) standards for installing energy efficient equipment or building practices as a condition of receiving program funding, and (3) procedures to ensure that reservations are made and incentives paid to PV systems that are very likely to be installed and operated as indicated in the funding application.

The board must establish funding for these incentives by (1) including in its FY 10-12 comprehensive plan an estimate of the total funding needed to support the incentives to qualifying residential systems and allocating up to one-third of this amount, (2) including in its FY 12-14 comprehensive plan an estimate of remaining funding needed to support the outstanding capacity blocks for the incentives and allocating up to one-half of this funding, (3) carrying forward any funding allocated to support these incentives until all capacity blocks have been filled, (4) allocating the balance of the funding as needed, and (5) monitoring the status of available funds and expected demand and including this assessment in its annual report to DPUC.

The board must post the incentives schedule, available funding, incentive estimators, and solar capacity remaining in the current block on its web site.

By January 1, 2013, and every two years thereafter through 2021, the board must report to the Energy and Technology Committee on progress toward the 30 MW goal.

Starting January 1, 2010, each electric company must solicit and file with DPUC, for its approval, one or more long-term power purchase contracts with owners or developers of customer-sited, nonresidential solar PV generation projects located in this state of less than 2,000 kilowatts (2 MW) in size. These systems must be located on the customer side of the meter and connected to the electric company's distribution system.

Solicitations conducted by the company must be for the purchase of solar renewable energy credits (solar RECs) produced by eligible projects over contracts that run at least 15 years. (Owners of renewable generation facilities can sell the power they produce on the wholesale electric market as “green power” or they can sell the RECs associated with this power separately from the power. ) The electric company may solicit proposals for a combination of renewable energy and associated solar RECs.

The electric companies must procure a total of at least 4. 35 million solar RECs. The production of a megawatt hour of electricity from a nonresidential solar renewable energy source placed in service on or after the bill's passage date creates one solar REC. The obligation to purchase credits must be apportioned to the companies based on their respective loads at the start of the procurement period, as determined by DPUC. These credits count against the companies' obligations under the renewable portfolio standard (RPS), which requires that they get part of their power from renewable resources.

The bill requires each electric company, within 180 days of the bill's passage, to propose a 10-year solar solicitation plan that includes a timetable and methodology for soliciting proposals for long-term solar RECs credits or energy contracts from in-state generators. The solicitation plan must be reviewed and approved by DPUC. Each company must submit contracts comprising at least 25% of its obligation by January 1, 2011, at least 50% by July 1, 2013, and at least 75% by July 1, 2015.

The approved solar solicitation plan must be designed to foster a diversity of solar project sizes and participation among all eligible customer classes, subject to cost-effectiveness considerations. Separate procurement processes must be conducted for (1) nonresidential systems between 10 kilowatts and 50 kilowatts, and (2) nonresidential systems between 50 and 2,000 kilowatts. (A typical residential PV system is five to 10 kilowatts. ) DPUC must give preference to competitive bidding for resources of more than 50 kilowatts, unless it determines that an alternative methodology is in the best interest of electric customers and the development of a competitive and self-sustaining solar market. Systems up to 50 kilowatts are eligible to receive a solar REC price equal to the highest accepted bid price in the most recent solicitation for systems of between 50 and 2,000 kilowatts, plus an additional incentive of 10%.

Each electric company must execute its approved solicitation plan. It must submit, for DPUC review and approval, its preferred solar procurement plan consisting of proposed contracts with independent solar developers. DPUC must hold a hearing in an uncontested case to approve, reject, or modify an application for approval of the procurement plan. DPUC may only approve the plan if it finds that (1) the company conducted the solicitation and evaluation by a fair, open, competitive, and transparent process; (2) approval of the procurement plan would provide the greatest expected ratepayer value from solar energy or solar RECs at the lowest reasonable cost; and (3) the procurement plan satisfies other criteria established in the approved solicitation plan. DPUC may not approve any proposal made under the procurement plan unless it determines that (1) the plan and proposals encompass all foreseeable sources of revenue or benefits and (2) the proposals, together with such revenue or benefits, would result in the greatest expected ratepayer value from solar energy or solar RECs.

DPUC may, in its discretion, retain an independent consultant with energy procurement expertise. The consultant must be unaffiliated with the electric company or its affiliates. It must not have benefited directly or indirectly from employment or contracts with the company or its affiliates in the preceding five years, except as an independent consultant. For purposes of the audit, the electric company must give the consultant immediate and continuing access to all documents and data it reviewed, used, or produced in its bid solicitation and evaluation process. The company must make all its personnel, agents, and contractors used in the bid solicitation and evaluation available for interview by the consultant. The company must conduct any additional modeling requested by the independent auditor (apparently, the consultant) to test the assumptions and results of the bid evaluation process. The consultant may not participate in or advise the company with respect to any decisions in the bid solicitation or bid evaluation process.

The electric companies can resell or otherwise dispose of the energy or solar RECs they purchase, but they must net the cost of payments made to projects under the contracts against the proceeds of the sale of energy or solar RECs. The difference must be credited or charged to their customers through a reconciling component of electric rates as determined by DPUC.

DPUC's administrative costs in reviewing the procurement plan and the costs of the consultant must be recovered through a reconciling component of electric rates as determined by DPUC. The electric company is entitled to recover its reasonable costs of complying with its approved solar procurement plan through the same type of mechanism.

If DPUC has not received proposed long-term solar REC contracts by the deadlines noted above, it must notify the electric company and the Renewable Energy Investments Board of the shortfall. DPUC may, upon petition by the electric company, grant it an extension of up to 90 days to correct this deficiency. If DPUC does not do this, the board must issue one or more requests for proposals (RFPs) to address the shortfall. The board must perform an initial review of each proposal, examine the financial and technical viability of each, and analyze project costs and benefits for the purpose of selecting projects that will promote the provision of long-term solar RECs. Upon selection of the projects, the board must forward the projects to each electric company for an engineering review. For each project, each electric company must analyze the interconnection point and their related costs, reliability, and other project impacts to determine whether the project will promote the provision of additional long-term solar RECs.

Each electric company must provide the results of its analysis to the DPUC, which must conduct a proceeding to determine whether to approve or reject each project. The reasonable administrative costs associated with the procurement of long-term solar RECs must be collected by the distribution company, maintained in a separate interest-bearing account and disbursed to the Clean Energy Investment Fund each quarter.

Within 60 days after DPUC approves the procurement plans submitted by January 1, 2011, it must report to the Energy and Technology Committee. The report must document, for each procurement plan: (1) the total number of solar RECs bid relative to the number of credits requested by the electric company, (2) the total number of bidders in each market segment, (3) the number of contracts awarded, and (4) the total weighted average price of the solar RECs or energy purchased. DPUC may not report individual bid information or other proprietary information.

The bill requires each electric company, by July 1, 2010, to file with DPUC for its approval, a tariff for production-based payments to owners or operators of grid-connected solar projects that are one megawatt or larger.

The tariffs must provide production-based payments for at least 15 years from the project's in-service date. Under the tariff, the project owner receives a cost-based price that DPUC determines. The price consists of the fully allocated cost of constructing and operating a solar renewable energy source between one to 7. 5 MW, if it were built and operated by an electric company. In calculating the tariff, DPUC must consider actual cost data for solar energy sources built and operated by an electric company under the bill, taking into consideration all available state and federal incentives.

The tariffs must include a per-project eligibility cap of 7. 5 MWs and an aggregate eligibility cap of 50 MWs, apportioned among each electric company in proportion to its distribution load. The costs of the tariff are eligible to be included in any subsequent rates, so long as they are for projects that begin operations on or after the bill's passage. These costs must be recovered through a reconciling component of electric rates as determined by DPUC.

Starting July 1, 2010, electric companies may build, own, and operate solar electric generating facilities up to one-third of their proportional share of the 50 MW cap. Such development must be phased in over at least three years. These projects must be located on company-owned properties, brownfields, or other locations identified by DPUC for strategic placement of distributed (small-scale) generation. DPUC must authorize the electric company, in a contested case, to recover in rates its costs to construct, own, and operate the facilities, including a reasonable return on its investment. DPUC can do this if (1) the approval would result in a reasonable cost of meeting the solar energy requirements described above; (2) investment will not restrict competition or growth in the state's solar energy industry; or (3) the investment will not unfairly use the company's financial, marketing, distributing, or generating advantage due to its status as a utility in a way that would restrict competition in the market for solar energy systems.

The amount of renewable energy produced from energy sources receiving tariff payments or included in utility rates counts against the electric company's RPS.

By September 1, 2011, DPUC, in consultation with the Office of Consumer Counsel and the Renewable Energy Investments Board, must study the operation of the tariffs and report its findings and recommendations to the Energy and Technology Committee.

DPUC must suspend the tariff (1) when an electric company's share of the 50 MW cap is reached, or (2) three years from the tariff's effective date, whichever is earlier.

The bill requires the Clean Energy Fund, by July 1, 2010, to complete, or cause to be completed by private vendors, a comprehensive solar feasibility survey of facilities owned or operated by the state with a load of 50 kilowatts or more. (The Legislative Office Building has a load of approximately 700 kilowatts. ) The fund must do this in consultation with the OPM and the Department of Public Works, within available funding. The survey must rank state-owned or-operated facilities based on their technical feasibility to accommodate PV generating systems by considering such factors as (1) on-site energy consumption; (2) building orientation; (3) roof age and condition; (4) shading and the potential for obstruction to sunlight over the life of the solar system; (5) structural load capacity; (6) availability of ancillary facilities, such as parking lots, walkways or maintenance areas; (7) nonenergy related amenities; and (8) other factors that the Clean Energy Fund considers may affect the technical feasibility of such projects.

The bill requires OPM, in consultation with the Clean Energy Fund, to issue one or more RFPs for deploying PV systems at state-owned or-operated facilities. OPM must do this within available funding. The RFP must be structured to maximize the state's ability to secure incentives available from the federal government or other sources. OPM may seek in any RFP the services of an entity to finance, design, construct, own, or maintain PV systems under a long-term solar services agreement. Any entity chosen to provide these services is not considered a public utility subject to DPUC jurisdiction. .

The bill establishes a funding cap for all of the programs described (the residential, nonresidential, and utility-scale PV programs and the solar thermal programs). For the period from January 1, 2010 through June 30, 2012, the aggregate net annual cost recovered for (presumably from) electric ratepayers may not exceed 0. 5% of total retail electricity sales revenues of each electric company. For the period between July 1, 2012 and June 30, 2014, the cap is 0. 75% of these revenues, and for each 12-month period starting July 1, 2014 and thereafter for the duration of the programs established under the bill, the cap is 1% of these revenues. DPUC must net out the incentives paid by the Clean Energy Fund for solar deployment programs against these caps.

If DPUC projects that the annual cost cap will be exceeded, it may (1) delay or modify the development of solar electric generating facilities by electric companies, (2) temporarily suspend the availability of production-based incentives under the tariff for utility-scale projects for customers not already eligible to receive these incentives, and (3) extend the scheduled electric company plans for procuring solar RECs from nonresidential customers. If the DPUC determines that these measures are required, it must reduce proportionally the annual funding for the affected programs but only to the extent required to bring projected annual costs below the cost cap.

By January 1, 2013, DPUC must report to the Energy and Technology Committee on the cost and charges involved in the implementation of this program (apparently all of the programs subject to the cap), including a cost-benefit analysis.

Under current law, the electric companies were required to file with DPUC by July 1, 2008, one or more long-term power purchase contracts from Class I renewable energy source (e. g. , wind power or fuel cell) projects. To be eligible, the projects had to (1) have received funding from the Clean Energy Fund, (2) be located in Connecticut, and (3) be at least one MW in size. The contracts had to provide for 125 MW of generating capacity prior to October 1, 2008, and 150 MW thereafter. The electric companies have not fully met these requirements and the projects covered by approved contracts have not yet been built.

The bill delays the step-up to 150 MW to October 1, 2010 and requires the companies' submission to include at least an additional 45 MW to address project attrition after contract execution with the intent that at least 150 MW of capacity reach commercial operation.

It requires DPUC, in consultation with the Office of Consumer Counsel and the Renewable Energy Investments Board, to study the operation of this program and report its findings and recommendations to the Energy and Technology Committee by September 1, 2010.

Yea

Nay

(03/19/2009)