AN ACT CONCERNING SOLAR POWER.

This bill requires 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 35 megawatts 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 bill requires that the program be funded by the existing renewable energy surcharge on electric bills.

The bill requires each electric company to file, by July 1, 2010, a tariff with the Department of Public Utility Control (DPUC) for its approval, for production-based payments to owners or operators of large solar projects. The bill allows an electric company to build solar projects under this provision under certain circumstances (although it does not amend CGS § 16-244e, which generally bars the companies from owning power plants or other generation resources).

The bill requires the electric companies to seek to enter into long-term contracts to buy the power produced by solar generating projects. The companies must seek contracts from large nonresidential PV systems and from smaller systems, which can be owned by nonresidential or residential customers. It appears that the latter systems can include solar electric technologies beyond PV systems. All contracts are subject to DPUC approval. The bill entitles the smaller eligible systems to receive 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 the Clean Energy Fund, in consultation with 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 DPW, in consultation with the fund, to issue one or more requests for proposals for the deployment of these systems on these facilities. The bill authorizes $ 150 million in bonding for this program. The bonds are subject to standard statutory issuance and repayment provisions.

By law, electric companies and competitive electric suppliers must provide a billing credit to their customers who generate power from class I resources such as solar or wind power or from certain hydropower facilities. The bill allows these “net metering” customers that are local governments or educational, religious, or nonprofit organizations to transfer the credit to related customers.

EFFECTIVE DATE: July 1, 2009, for the bond authorization; upon passage, for the remaining provisions.

Under the bill, the Clean Energy Fund must offer direct incentives for the purchase or lease of qualifying residential PV systems that reduce their costs based on their performance. 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 that advises Connecticut Innovations, Inc. must consider solar system characteristics, such as operational efficiency, size, location, shading, and orientation, when determining the type of incentive.

By January 1, 2010, the fund must develop a proposed schedule for offering the incentives over the duration of the program. The schedule must (1) provide for at least eight “blocks” and associated solar capacity and incentive levels; (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 fund must determine whether to establish a uniform statewide incentive schedule or separate incentive schedules for each company's service territory. The board must retain a consultant with expertise in solar energy program design to help develop the incentive schedules. The fund must hold public hearings on the proposed schedule at three or more locations in the state and summarize the comments and its responses to them in the final schedule.

The fund must establish and periodically update eligibility criteria, including requirements related to (1) which customers may participate, (2) equipment sizing and technical specifications, (3) installation standards, (4) energy efficiency conditions, (5) equipment warranties, (6) performance, and (7) relocation of equipment. The criteria cannot unreasonably restrict the host's ability to designate an installer or other third-party developer, system owner, or installer to receive the incentive. Any unclaimed incentives must go back to the current block of incentives.

The fund must establish procedures to provide reasonable assurance that rebate reservations are made and incentives are paid out only to qualifying systems demonstrating a high likelihood of proper installation and operation. The fund must establish a dispute resolution process. It may establish (1) nonrefundable application fees or performance bond requirements, (2) performance milestones, (3) deadlines for project completion and relinquishment of position in incentive queue, or (4) post-installation adjustment or denial of performance-based incentives.

The fund must post the up-to-date status of the amount of incentives and solar capacity remaining in the current block on its web site.

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 2 megawatts or larger.

The tariffs must provide production-based payments for at least 20 years from the project's in-service date. Under the tariff, the owner can chose to receive a price that is (1) not more than the total of the comparable wholesale market price for generation, calculated over the most recent 24-month period plus 11 cents per kilowatt hour; (2) the real-time locational marginal pricing rate adjusted for losses (i. e. , the spot market price) plus 11 cents per kilowatt hour; or (3) not more than the total of the comparable wholesale market price for energy and capacity plus the electric company's full avoided costs of providing standard offer and distribution service. The full avoided costs includes various annually charges, e. g. , those associated with congestion on the transmission system. The tariffs must include a per project eligibility cap of 7. 5 megawatts and an aggregate eligibility cap of 50 megawatts, apportioned among each electric company in proportion to its distribution load. The cost of the tariff can be recovered through rates charged for standard service (the service electric companies provide to small- and medium-sized customers who have not chosen a competitive supplier), so long as the payments are for new projects.

Electric companies may construct, own, and operate solar electric generating facilities up to one-third of their proportional share of the total cap amounts. DPUC must authorize the company to recover in rates its costs to construct, own, and operate the facilities, including a reasonable return on its investment, if (1) this would result in the lowest reasonable cost of meeting the bill's requirements and (2) the investment would not restrict competition or growth in the state's solar energy industry or rely on an unfair advantage of the company as a utility.

The amount of renewable energy produced from Class I renewable energy sources receiving tariff payments or included in utility rates counts against the renewable portfolio standard, which requires electric companies to get part of their power from renewable resources. By September 1, 2011, DPUC, in consultation with the Office of Consumer Counsel and the Renewable Energy Investments Advisory Council, must study the operation of the tariffs and report its findings and recommendations to the Energy and Technology Committee.

By law, electric companies must develop, for DPUC approval, plans for procuring power and other resources such as savings from efficiency programs. Under the bill, notwithstanding any previously approved plan, starting on July 1, 2010 and for the next five years, each company must solicit proposals for long term contracts with large nonresidential PV generators. For these purposes, "nonresidential" includes all rate classes other than single-family homes and individual apartments qualifying for residential electric service.

The solicitations must be for the purchase of renewable energy credits (RECs) produced by eligible projects for 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. ) To be eligible, the contract must be with the owner or developer of a nonresidential solar PV project that is less than 2 MW in size, located on the customer side of the electric meter, and connected to the company's grid. On or before July 1, 2010, an electric company is not required to consider or enter into proposed long-term REC contracts that exceed $ 650 per megawatt hour ($ 0. 65 per kilowatt-hour) in the initial year of the procurement period, declining by 7% annually.

The electric company may solicit proposals for a combination of renewable energy and associated RECs. The aggregate procurement of RECs under these provisions must be at least 3,191,250. The production of a megawatt hour of electricity from a solar energy source first placed in service on or after the bill's passage creates one solar REC. The obligation to purchase the RECs must be apportioned to each electric company based on its respective share of the load in the state at the start of the procurement period, as determined by DPUC.

If the company receives reasonable proposals, it must file with DPUC for its approval, one or more long-term power purchase contracts with eligible projects. An electric company may use the RECs it procures through long-term contracting towards its obligations under the renewable portfolio standard. The bill does not preclude the resale or other disposition of energy or associated RECs the company purchases, so long as it nets the cost of payments made to projects under the long-term contracts against the proceeds of the sale of energy or RECs. The difference must be credited or charged to the company's customers through a uniform, fully-reconciling factor in distribution rates, subject to review and approval by DPUC.

The bill requires each electric company, within 180 days of the bill's passage, to propose a solar solicitation plan that includes a timetable and methodology for soliciting proposals for long-term solar RECs or energy contracts. The plan is subject to DPUC review and approval. Contracts comprising at least 25% of the company's obligation must be submitted for DPUC approval by January 1, 2011, and at least 75% of the obligation by July 1, 2013. However, the bill does not appear to specify any obligations as to the amount of power that must be contracted for under these provisions.

There must be separate procurement processes for nonresidential systems between 10 kilowatts (KW) and 50 KW and for 51 KW to 2 MW. (A kilowatt is the amount of power used by 10 100-watt lightbulbs. A megawatt is 1,000 KW. ) The procurements must be open to all customer classes, subject to cost-effectiveness consideration. DPUC must give preference to competitive bidding for resources of more than 50 KW, unless it determines that another methodology is in the best interests of the company's customers and the development of a competitive and self-sustaining solar market. Smaller systems are eligible to receive a standard REC price equal to the highest accepted bid price in the most recent large system solicitation, plus an additional incentive of up to 10% as DPUC considers necessary to elicit proposals from this market segment.

The bill requires each electric company to execute its approved solicitation plan. It requires the company to submit to DPUC, for its review and approval, the company's preferred procurement plan comprised of any proposed contracts with independent solar developers or electric company utility affiliates and, where applicable, electric company proposals to develop solar projects as a rate-based investment. The bill implies that electric companies can build and operate solar projects under these provisions. The DPUC's administrative costs in reviewing the company's procurement plan must be recovered in rates.

The bill allows DPUC to retain an independent auditor with expertise in the area of energy procurement. The auditor must be unaffiliated with the electric company or its affiliates and may not, directly or indirectly, have benefited from employment or contracts with them in the preceding five years except as an independent auditor. The auditor may not participate in or advise the electric company with respect to any decisions in the bid solicitation or bid evaluation process.

If applicable, the auditor must audit of the electric company's bid solicitation and evaluation process to ensure that it meets the standards the bill establishes for DPUC to approve a contract (see below). For purposes of the audit, the electric company must give the auditor immediate and continuing access to all documents and data it reviewed, used, or produced in its bid solicitation and evaluation process. The electric company must make all its personnel, agents, and contractors used in the bid solicitation and evaluation available for interview by the auditor. The electric company must conduct any additional modeling requested by the auditor to test the assumptions and results of the bid evaluation process. Within 60 days after the electric company's selection of solar resources, the auditor must file a report with DPUC containing his or her findings, specifically reporting any deficiencies.

DPUC must hold a hearing as part of a contested case to approve, reject, or modify a company's application. DPUC may only approve the plan if it finds that (1) the company's solicitation and evaluation was the result of a fair, open, competitive, and transparent process; (2) approval of the plan would produce the lowest reasonable cost of solar energy or RECs; and (3) the plan satisfies other criteria established in the approved solicitation plan. Where the electric company has proposed to develop and rate-base, customer-sited solar facilities, DPUC must also determine that (1) the investment will not restrict competition or restrict growth in the state's solar energy industry and (2) the company will not unfairly use any financial, marketing, distributing, or generating advantage that it has as a utility in a way that would restrict competition in the market for solar energy systems.

The bill entitles the electric company to recover its reasonable costs of complying with its approved solar procurement plan. If DPUC authorizes the electric company to enter into contracts under these provisions, it must also provide for remuneration to the company equal to 4% of the annual payments under the contract to compensate the company for accepting the financial obligation of the long-term contract. DPUC may not consider this remuneration as a cost of procuring solar resources from unaffiliated developers for purposes of bid evaluation.

The bill requires the Clean Energy Fund, in consultation with DPW, to complete July 1, 2010, a comprehensive solar feasibility survey by 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 survey must rank state facilities based on their technical feasibility to accommodate PV 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 fund considers relevant.

DPW, in consultation with the fund, must issue one or more requests for proposals (RFPs) for the deployment of PV systems at state facilities. The RFP must be structured to maximize the state's ability to secure incentives available from the federal government or other sources. DPW may seek the services of an entity to finance, design, construct, own, or maintain the PV system under a long-term services agreement. Any entity chosen to provide such services is not be considered a utility.

Any contract entered into between DPW and such an entity must require that the state retain title to any REC or other tradable green certificate created by the system over its life. The state must retain these credits.

By law, electric companies and competitive electric suppliers must provide a billing credit to their customers who generate power from class I resources. In most cases, the credit is the customer's net production power multiplied by the company or supplier's retail rate.

The bill allows a local government or a religious, educational, or 501(c)(3) nonprofit organization owning or operating a Class I renewable energy source with a capacity of up to 2 megawatts to transfer its net metering credits. Local governments include school districts, special districts, and housing authorities in addition to towns, cities, and boroughs. These entities can transfer the credit to another of their accounts, so long as it is metered separately from the load served by the renewable facility and is served by the same electric company as the renewable facility. In the case of an organization, the credit can be transferred to an organization member who resides or has a place of business in the service territory of the electric company that serves the renewable facility.

The bill requires that the transferred credits be denominated in dollars and applied whether or not the receiving customer is in the same rate class as the generating customer. It requires that the power produced from the facility first be netted against on-site electricity consumption and then against the load of the receiving customer based on a percentage allocation specified by the generating customer. At least 60 days before the facility becomes operational, the generating customer must notify its electric company, in writing, of who will receive the credits. The generating customer may change the receiving customer no more than once annually by providing the electric company with 60 days' written notice of the change. The facilities eligible for this arrangement are subject to generally applicable interconnection standards but may not be restricted in design or operation to the use of the metered load served by the facility. This means that the renewable facility can be designed to produce more power than its owner will use. The facilities may earn RECs under the long-term contracts described above or other incentives generally available to such facilities.

The bill requires the Clean Energy Fund to make an unspecified amount of money available to the municipal renewable energy and efficient energy grant account for the purpose of providing grants to local governments and tax-exempt organizations consistent with the purposes of these provisions. The bill does not preclude community solar facilities from eligibility for funding under other Clean Energy Fund programs for which they would otherwise qualify.

Yea

Nay

(03/19/2009)