As of March 2005, 18 states and the District of Columbia have created or committed to some form of Renewable Portfolio Standards (RPS) program.¹ Efforts to enact RPS programs in other states continue to gain momentum. These programs are already important financial drivers for renewable projects. Some state RPS programs currently offer price premiums that are more valuable than the federal income tax credit under Section 45 of the Internal Revenue Code, recently extended by congress to certain renewable projects.² (click on the numbers to read footnotes at the end of this article)

Each state’s RPS program is unique and offers different opportunities for different renewable power projects. This article will discuss some of the key features of those RPS programs. ³

Background
Renewable Portfolio Standards are legal standards that require or encourage utilities or load-serving entities to supply a certain amount of their load from “renewable” energy sources. RPS programs are intended to achieve a variety of public policy objectives: (1) reduce air pollution from “dirty” power plants; (2) reduce greenhouse gas emissions; (3) reduce reliance on foreign oil; (4) minimize impact of price volatility in fuel sources for electricity generation by diversifying the fuel source base; and (5) encourage production of electricity from local energy resources.

National and international events in recent years—e.g., the California energy crisis of 001, the 9/11 attacks, instability in the Middle East, greater recognition that global warming is occurring, increasing fossil fuel prices—have motivated state policymakers to develop RPS programs.

Opponents of RPS programs argue that free markets—not government—should determine energy sources and that RPS programs impose a cost on ratepayers by forcing utilities to buy power from uneconomic generation sources. Proponents respond that requiring more renewable power will make renewables more economic ⁴ and might reduce energy prices in the long term by providing a hedge against future increases in fossil fuel prices. They also argue that most RPS programs are designed to encourage competition among renewable power sources, which will encourage development of lower-cost renewables.

It is unlikely that renewable portfolio standards will be enacted on a national level any time soon. The House Republican leadership strongly opposes a national renewable portfolio standard. ⁵ The absence of a national standard has cleared the field for states to act. In 1996, only Iowa and Minnesota required utilities to have a certain amount of renewable generation. Massachusetts’ enactment of an RPS statute in 1997 began a trend toward RPS programs that has accelerated in the last few years.

Which Electric Providers Must Meet Portfolio Requirements?
Some RPS programs require compliance by all retail electric providers, but some of the largest programs limit compliance to only certain electric providers, such as public utilities. Municipal electric companies and electric cooperatives are sometimes exempted from compliance. California currently requires compliance only from its three largest investor-owned utilities (IOUs). ⁶ Minnesota imposes a mandate on its largest utility but sets good-faith goals for all other electric providers. New York excludes the New York Power Authority, the Long Island Power Authority, and all municipal utilities. Colorado’s program includes retail electric providers with over 40,000 customers (currently the nine largest utilities). Texas includes all retail electric providers.

Mandates and Percentages
Perhaps the most important aspect of an RPS program is whether or not it imposes mandates on retail electric providers. Of the 19 state RPS programs in effect or under development, 17 programs require generation or procurement of renewable power, one (Illinois) sets goals only, and one (Minnesota) places requirements on one utility while setting good-faith standards for other retail electric providers.

Most of the mandatory RPS programs require retail electric providers to generate or procure a percentage of their load in megawatt-hours from renewables, with the percentage requirements increasing over time. ⁷ The percentage requirements under RPS programs vary widely and do not always indicate the state’s commitment to renewable power. For example, Arizona’s requirements (utilities required to have 0.8% renewable power in 2004, increasing to 1.1% by 2007) seem modest compared to Maine’s (retail electric providers required to have 30% renewable power by 2002), but Arizona’s program offers greater opportunities to renewable developers because Maine already generates enough renewable power to meet its requirements. ⁸

Three programs (Texas, Minnesota, and Iowa) base some or all of their requirements on megawatts installed, not megawatt-hours. ⁹ In theory, wind projects and other intermittent sources would fare better in a megawatt-based program than in a megawatt-hour–based program because they would be credited for their full capacity despite having lower capacity factors. But the Texas program functions like a megawatt-hour–based program. The Electric Reliability Council of Texas (ERCOT), the program administrator, uses a “capacity conversion factor” to convert the program’s capacity requirements into megawatt-hour purchase requirements for each retail electric provider, then allocates each provider its share of the purchase requirement based on its share of the overall electric load.

Minnesota’s RPS statute contains mandatory requirements for XCel Energy and good-faith goals for other retail electric providers. XCel must have 1% renewables in its portfolio by 2005, increasing by 1% each year up to 10% by 2015 and must have 300 MW of wind power by 2010. These requirements do not include 825 MW of wind power and 110 MW of farm closed-loop biomass power that XCel was required to generate or procure by 2002 under prior legislation. Other providers are simply required to make good-faith efforts to reach the same percentage goals as XCel. The Minnesota Public Utilities Commission (PUC) appears to be vigorously implementing the good-faith program, but it is unclear whether the PUC will attempt to enforce the good faith standards if providers have any difficulty meeting them.

Renewable Energy Credits
RPS programs are likely to confer some form of price premium on a renewable power project. Increasingly, states are recognizing the value of renewable energy in the form of renewable energy credits (RECs). RECs are certificates of proof that a certain amount (generally 1 MWh) of electricity has been generated by a renewable power source. The REC represents the renewable characteristics of a megawatt-hour, not the megawatt-hour itself.

Generally, RECs are “unbundled” from electricity and tradable. ¹⁰ Tradable RECs create a more liquid market for renewable power. The result to the public should be a more efficient renewable market and lower-cost renewable power.

There is no need to track electrons. With tradable RECs, retail electric providers can satisfy renewable portfolio standards either by generating renewable power and RECs themselves, purchasing power and RECs directly from the renewable power generator, or purchasing RECs without purchasing the associated power. A renewable generator can sell its power to one retail electric provider and its RECs to another. A retail electric provider can sell surplus RECs to another provider.

A tradable REC program must be supported by a certificate-trading system. In a typical system, renewable generators register with regulators in the state in which they want to qualify. Then, renewable generators and retail electric providers register with a system administrator (usually the local grid operator). As renewable power is generated, generators periodically report their output to the system administrator, who verifies the qualifying status of the output. The administrator then creates RECs and assigns them to the generator’s account. Generators then transfer the RECs to the account of REC purchasers during specified transfer windows. RECs can be bought and sold multiple times within such windows. The RPS programs set a date and time when all retail electric providers subject to the program must have the requisite number of RECs in their account.

The New England Power Pool Generator Information System (NEPOOL GIS) and the Texas trading program administered by ERCOT are the major certificate-trading systems. The NEPOOL GIS tracks attributes of all generation, providing a mechanism for emissions disclosures and other required environmental reporting, while the Texas system tracks only renewable attributes. Wisconsin contracts with a private company, Clean Power Markets Inc., to run its certificate-trading system. In Nevada, the Public Utilities Commission is the system administrator.

PJM is developing a Generation Attribute Tracking System (PJM GATS) modeled on the NEPOOL GIS system. This system is scheduled to begin operation by the end of 2005. It will track attributes of all generation, not just renewables. PJM GATS is likely to include an annual reporting and trading schedule, not a quarterly schedule like the NEPOOL GIS.

The Western Governors’ Association (comprising 11 western states) and other stakeholders are developing the Western Regional Energy Generation Information System (WREGIS), anticipated to be operational in late 2005. WREGIS will initially serve the function of verifying renewable generation and standardizing information to enable buyers and sellers of renewable power and attributes to conduct sales transactions with confidence. But in the future, WREGIS could serve as the platform for trading certificates. If California and Colorado adopt REC trading programs they will consider using WREGIS as administrator, and other states would certainly follow.

Penalties
The strength of enforcement mechanisms is an important factor in how a state RPS program functions. In some states, utilities that fail to generate or purchase the requisite percentage of renewable power (or to acquire RECs in lieu of generating or purchasing power from renewable sources) must make an alternative compliance payment (ACP) for every kilowatt-hour or megawatt-hour by which they fall short of the requirement. The ACP is paid to the applicable regulatory agency in the state and is generally used to help fund grants, loans, or price supports to renewable energy projects.

Connecticut ($55/MWh), California ($50/MWh), Massachusetts ($50/MWh), New Jersey ($50/MWh) ¹¹, Rhode Island ($50/MWh) and Texas (lesser of $50/MWh or 200% of the average market price for RECs in the previous year) have set the highest ACPs. ¹²

Absent other sanctions for non-compliance, the ACP becomes the ceiling on the price of RECs—there would be no reason for a utility to purchase RECs at a price that is higher than the penalty for non-compliance. If the supply of renewable power is tight (at or just below the percentage requirement) in a given year, the market price for RECs will approach the ACP.

Other RPS states have not set up specific enforcement mechanisms. In most cases, agencies in those states can impose fines or revoke licenses in the event of non-compliance with the RPS program. At this time, there are no reported instances of a retail electric provider being sanctioned by regulators for non-compliance.

Price Floors/Ceilings
In some states, other market support mechanisms may help support renewable projects. The Massachusetts Technology Collaborative (MTC), a quasi-public entity, makes low-interest loans to selected projects and enters “collar” arrangements where the renewable generator can put RECs to MTC at a designated low price and MTC can call RECs at a designated high price. MTC would then attempt to resell any RECs that it purchases. This gives the renewable generator a guaranteed price range for the sale of its RECs, facilitating long-term power sales agreements and financeability of projects.

Long-Term Power Sales Contracts
Long-term power sales contracts are critical to the success of a renewable project. Lenders are often reluctant to loan money against a project with an uncertain revenue stream. Long-term power sales contracts provide renewable generators, and their lenders, with greater certainty of revenues.

Under most RPS programs, it is left up to the renewable electric providers and generators whether or not to enter into long-term contracts. However, the California and New York RPS programs will rely heavily on long-term contracts. Under the California RPS, each investor-owned utility (IOU) solicits competitive bids from renewable generators every year. The solicitations are approved by the California Public Utilities Commission and seek 10-year, 15-year, and 20-year contracts. In New York, the Public Service Commission has indicated a preference for long-term contracts. In both states, policymakers assume that long-term contracts benefit the utilities and the public by offering the best opportunity for lower bids and cost savings.

Perfecting a Security Interest in RECs
Before lending to a renewable project, lenders will want to perfect and otherwise protect their interest in the project’s RECs in order to be certain that they can take possession of all RECs in the event of foreclosure or transfer. Generally, RECs are treated as “general intangibles” under Article 9 of the UCC. Under most states’ laws, security interests in general intangibles are perfected by filing a financing statement with the secretary of state in the state of the borrower’s chief executive office. The legal structure underlying RECs is still evolving, so lenders should investigate whether other filings should be made to perfect their security interests. It would be wise to investigate whether a state office (where renewable generators are required to register) or a system administrator (if applicable) will accept such a filing. A lender could also require that the borrower name the lender as a designated representative when the borrower files as a renewable generator with the state registration office.

Mid-Course Reviews and Safety Valves
Some RPS programs (e.g., New Jersey by 2008, New York by 2009, and Rhode Island by 2010 and 2014) require a mid-course review, in which state regulators or lawmakers will review the RPS program and could possibly scale it back. Other programs (e.g., Hawaii) expressly allow for requirements to be waived if they prove to be too costly to retail electric providers and consumers. Renewable generators relying on these programs without binding long-term contracts should keep these considerations in mind with respect to these markets.

Eligible “Renewable” Energy Fuel Sources
Different “renewable” energy sources are eligible under different RPS programs. The following projects are eligible under most programs:

• Solar
• Geothermal
• Wind
• Landfill Gas
• Some form of biomass (sometimes limited to closed-loop, clean open-loop, low emission, etc.)
• Small (5 MW–30 MW) or low-impact hydro

Not surprisingly, each state’s RPS program features energy sources that are prominent in that state or region. Northeast states uniformly include wood-fired and small hydro projects. Some northern and upper midwestern states allow larger hydro projects. ¹³ Midwestern states explicitly include agricultural-related biomass. ¹⁴ Coastal states include tidal or wave power projects. ¹⁵

Other eligible fuel sources in some states include poultry waste, ¹⁶ animal waste, ¹⁷ digester gas, ¹⁸ and fuel cells. 2¹⁹

Many RPS programs confer eligibility on projects using fuel sources that are not, strictly speaking, “renewable.” Some RPS programs include waste-to-energy facilities (sometimes under limited circumstances). ²⁰ California’s RPS includes waste tire projects. Pennsylvania’s new program includes projects fueled by coal mine methane and waste coal. In New York, plants fueled by eligible biomass, biogas, and biofuels qualify even when co-fired with fossil fuels, though they only qualify for the electricity attributable to the eligible fuel. Minnesota’s good-faith program also allows credit for co-firing to the extent that the renewable fuel is used. In Massachusetts, plant owners can seek a waiver to include a co-fired plant in the program.

Favored Renewable Energy Sources
Some RPS programs favor certain renewable energy sources over others. Three states—Connecticut, Maryland, and New Jersey—create two or more classes of renewables. Class 1 generally features the most-favored renewables—solar, wind, fuel cell, ocean/tidal, landfill gas, closed-loop or clean biomass, and smaller hydro. Class 2 includes less favored sources such as waste-to-energy and other hydro or biomass. Retail providers are required to meet overall percentage requirements using any type of qualified renewable source, but must meet a large portion of the requirement using only Class 1 sources.

Another approach is weighing generation from certain renewable sources more heavily. Under regulations proposed by the New Mexico Public Regulatory Commission to implement the state’s RPS, every kilowatt-hour generated by solar projects will count as 3 kWh toward compliance; every kilowatt-hour generated by biomass, geothermal, landfill gas, and fuel cell projects will count as 2 kWh toward compliance, and every kilowatt-hour generated by wind and hydro projects will count as 1 kWh toward compliance. Maryland gives extra credit toward its RPS requirements for output generated by new wind projects. ²¹

Four states (Arizona, Colorado, New Jersey, and Pennsylvania) have a special set-aside for solar projects. Arizona requires that solar power comprise 60% of its utilities’ renewables portfolio by 2004. Colorado and Pennsylvania’s set-asides are more modest. New Jersey sets a separate percentage requirement for solar power, and requires utilities to purchase separate RECs (solar RECs) to satisfy that requirement. Minnesota’s program includes a small set-aside for biomass projects.

New York’s RPS encourages development of distributed generation by creating a special tier for customer-sited solar, wind (up to 300 MW) and biomass projects. Utilities must buy 2% of the overall renewables increment from eligible customer-sited facilities, but output from these facilities will only count toward the requirement if it is not sold to the utility under a mandatory net-metering regime.

Emissions and Technology Standards
Most RPS programs do not restrict the eligibility of combustion projects (e.g., biomass) using an eligible fuel on the basis of their emissions. Connecticut imposes some restrictions. To qualify as a Class I renewable resource in Connecticut, most open loop biomass plants must average less than 0.075 pounds/MMBtu (fuel input) of NOx emissions in a calendar quarter. Connecticut also includes some older biomass plants that would have more difficulty meeting Class I standards—they may qualify as a Class II resource in Connecticut if they average less than 0.2 pounds/MMBtu (fuel input) of NOx emissions in a calendar quarter.

Similarly, most states do not attempt to restrict the technology that may be used to combust an eligible fuel. However, in Massachusetts, where the RPS program is limited to “new” renewable resources, biomass plants using “pile burn, stoker combustion and similar technologies” do not qualify as renewable resources.

Existing Versus New Projects
Most RPS programs confer eligibility on existing renewable projects as well as new ones. Other states seek to encourage new renewable projects by offering eligibility to projects placed in service after specified dates (vintage requirements). For example, projects must be placed into service on or after December 31, 1997 to qualify in Massachusetts; on or after September 1, 1999 to qualify in Texas; and on or after January 1, 2003 to qualify in New York (except for pre-existing wind, biomass, and very small hydro projects which may apply for inclusion). ²² These dates generally correspond to the date that the RPS program was enacted or announced. New Jersey imposes vintage requirements only on out-of-region projects.

Limiting eligibility to new projects focuses financial incentives on those projects, more directly advancing the policy goal of adding new renewable generation. But excluding existing renewable projects from an RPS program places those projects at a competitive disadvantage versus new renewables. Some existing RPS-ineligible renewable projects may shut down if retail electric providers stop purchasing their power or lower their offers in favor of power from RPS-eligible new renewable projects. Letting existing renewable projects go off-line just as new renewables are coming online defeats the policy purpose of increasing the overall percentage of renewables. Texas addressed this problem by allowing retail electric providers to offset purchases from existing ineligible renewable sources against their requirement to purchase power from eligible renewable sources.

California’s RPS program includes projects that are new and repowered projects (after January 1, 2002), and some existing renewable projects. Most new and repowered renewable projects are eligible for supplemental energy payments (SEPs) payable by the California Energy Commission, while existing projects are not eligible. ²³ Plants are considered repowered if they replace their prime generating equipment and demonstrate that they have made capital investments in the facility at least equal to 80% of the value of the repowered facility.

Some state RPS statutes do not state whether or not existing renewable projects are included in the programs. In these states, the regulatory agencies charged with administering the programs may end up deciding this question.

Geographic Reach
Many RPS programs confer eligibility on in-state projects and out-of-state projects that deliver power into the state or regional ISO territory. ²⁴ Counting out-of-state power toward RPS requirements can make policy sense. The public realizes at least some of the benefits of renewable power no matter where it is generated.

Although some state programs appear to have the same territorial limitations, there are subtle differences between some of them. The four New England programs (Connecticut, Maine, Massachusetts, and Rhode Island) allow qualifying projects located in or delivering power into ISO-NE territory to participate in their programs, but Connecticut also allows projects located in New York and several PJM states (New Jersey, Pennsylvania, Maryland, and Delaware) to qualify, even if the power from that project is not delivered into Connecticut—so long as the Connecticut PUC has determined that these states have developed RPS programs similar to Connecticut’s.

The PJM states with RPS programs (New Jersey, Pennsylvania, Maryland, and the District of Columbia) all include projects located in PJM territory. Pennsylvania does not include power from projects located outside PJM territory that deliver power into PJM territory. New Jersey does include imports, but only from projects for which construction began on or after January 1, 2003. Maryland and the District of Columbia’s RPS laws include projects located in a “state adjacent to” the PJM region, apparently even if the project does not deliver output into PJM territory. However, the staff of the Maryland Public Service Commission interprets the statute to include projects outside PJM territory only if they deliver power into PJM territory.

Multiple State Eligibility/No Double-Counting
Because renewable projects may qualify for RPS programs in states other than the state in which they are located, some renewable projects may qualify for more than one RPS program. The renewable developer should investigate which RPS program offers the best opportunity to its project. Many factors come into consideration, e.g., the demand for renewable power in an RPS program, REC, or renewable power prices (if the program has already come into effect), the state’s degree of commitment to the program, and the state’s enforcement tools and willingness to use them.

Many RPS statutes or regulations explicitly state that a project cannot generate and sell RECs or renewable attributes associated with the same output in more than one state RPS program, and it is unlikely that any statute or regulation will be construed to allow double-counting. Policymakers have decided (correctly) that double-counting would be a windfall for a renewable developer that qualifies in multiple states and would dilute the effectiveness of the RPS program. But there is nothing to prevent a renewable project from selling RECs in State A’s RPS program for a period of time, then stopping its participation in State A and selling RECs in State B’s program.

Do RECs or Attributes Transfer Under Older Power Sales Contracts?
Many existing, older renewable projects sell power as qualifying facilities (QFs) to public utilities at avoided cost under power sales contracts entered into under the Public Utilities Regulatory Policies Act of 1978 (PURPA). Not surprisingly, these contracts are silent on whether the buyers of power also purchase the renewable attributes associated with the power. Now that the renewable attributes have value (especially in states with tradable RECs), both the generators selling renewable power and the utilities purchasing renewable power want to claim ownership to those attributes. In October 2003, the Federal Energy Regulatory Commission (FERC) ruled that PURPA and related FERC regulations do not cause the automatic transfer of renewable attributes from a renewable generator to a utility under an avoided cost contract absent an express contractual provision to the contrary. However, FERC observed that RECs are the creation of state law and states themselves may decide that a sale of power at wholesale automatically transfers RECs to the power purchaser.

Most states with RPS programs have not yet reached this issue. The Maine Public Utilities Commission has ruled that QF contracts transfer attributes along with power to purchasing utilities. In March 2004, the Connecticut Department of Public Control decided that renewable attributes from certain renewable projects automatically transfer under Connecticut law from the generators to the public utility purchasing the power under a particular form of power sales contract. That decision is under appeal.

Analysis of Markets
State RPS programs are still developing, and existing programs are still evolving. Based on current information about legal structure and market conditions, we grade the current RPS market opportunities for developers as follows:

Best Opportunities for Developers—Key Features
California

• The RPS statute currently imposes percentage requirements on California’s three major IOUs (PG&E, SCE, and SDG&E). Requirements are already in effect. The final statutory requirement is 20% renewables by 2017. Stating in 2006, it will also apply to ESPs.
• The program is jointly administered by the California Public Utilities Commission (CPUC) and California Energy Commission (CEC). The CEC is managing issues relating to generator eligibility, while the CPUC is overseeing procurement by the IOUs.
• The CPUC and the CEC want to meet the 20% goal by 2010. The CPUC is requiring the IOUs to submit plans for RPS procurement with an emphasis on reaching 20% by 2010. A bill that would have mandated 20% by 2010 (among other provisions) was vetoed by Governor Arnold Schwarzenegger. Nevertheless, Governor Schwarzenegger is a strong supporter of accelerating and raising RPS requirements.
• Each IOU will annually solicit bids for long-term (10-, 15-. and 20-year) power purchase contracts (including power and “environmental attributes”) from renewable generators. Each of the IOUs has issued an RFP for renewable contracts. At this writing, SCE has submitted its proposed contracts to the CPUC for approval, and PG&E and SDG&E are expected to do so soon.
• Generators must sell power and environmental attributes to the IOUs together, reflecting California’s skepticism of any device resembling tradable contracts in the wake of the Enron fiasco.
• The ACP is $50/MWh.
• The CEC is developing a registration system for tracking renewable generators and power. Participation is presently limited to generators selling or delivering power into California. In time, the California program may use WREGIS (currently under development, the CEC is a co-sponsor), and may include tradable RECs and projects not selling or delivering into California.
• The CPUC and the CEC estimate that meeting 20% by 2010 would add 4,200 MWs of renewable capacity between 2003 and 2010. This might be an underestimate. California’s RPS program could potentially cause the development of more renewable generation more quickly than any other program.
• Renewable developers must be certified by the CEC to participate in the program.

JM Region (Mid-Atlantic States)

• Key features of the New Jersey, Maryland, Pennsylvania, and District of Columbia RPS programs
• PJM territory (all or part of New Jersey, Pennsylvania, Delaware, Maryland, West Virginia, Ohio, and Virginia) can be considered as one market since projects located in the territory are eligible for New Jersey, Maryland, Pennsylvania, and the District of Columbia’s RPS programs.
• New Jersey’s RPS program was finalized in 2004 and is already in effect. Total requirements (inclusive of Class I and Class II) start at 3.25% and go up to 6.5% by 2008. Further requirements could reach 20% by 2020, but first the New Jersey BPU will review the program in 2008. There is a special set-aside for solar.
• Maryland’s program was enacted in 2004 and takes effect in 2006. Requirements start at 1% in 2006–07 and go to 7.5% by 2019. New wind facilities receive extra credit toward the requirements.
• Pennsylvania’s program was enacted in 2004 and takes effect in 2007. The program includes two tiers. Tier I requirements begin at 1.5% in 2007 and rise to 8% by 2020. Tier II requirements begin at 4.2% in 2007 and rise to 10% by 2020. There is a special set-aside for solar.
• The District of Columbia program was enacted in 2004 and takes effect in 2007. The program has two tiers. Tier one begins at 1.5% in 2007 and rises to 11% by 2022. Tier two is slowly phased out. There is a special set-aside for solar.
• Pennsylvania does not count power imported into PJM territory generated by projects outside of PJM territory. New Jersey counts imports into PJM territory only from projects constructed on or after January 1, 2003. Maryland allows imports and might allow power from projects in states adjacent to PJM even if the power is not delivered into PJM territory.
• All four programs will use tradable RECs. According to Evolution Markets, New Jersey Class I RECs for the 2005 reporting year are trading in the $7 to $8 range. These prices may go up as the New Jersey percentage requirements go up and the Maryland, District of Columbia, and Pennsylvania programs take effect.
• ACP levels are high in New Jersey ($50/MWh) and Pennsylvania ($45/MWh), and lower in Maryland ($20/MWh for Tier 1) and District of Columbia ($25/MWh for Tier 1).
• These four programs together will cause the installation of several thousand MW of new renewable generation in PJM territory. Some of Pennsylvania’s requirements will be satisfied by eligible coal methane and waste coal–fired projects.
• All four programs anticipate an REC trading system to be administered by PJM GATS. This system is still under development and may be operational by the end of 2005.
• To participate in these programs, renewable developers should contact the New Jersey Board of Public Utilities, the Maryland Public Service Commission, the District of Columbia Energy Office, and the Pennsylvania Public Utility Commission, respectively. When the PJM GATS system is adopted, renewable developers should also contact PJM.

New York

• In September 2004, the New York Public Service Commission (PSC) adopted an RPS program that is scheduled to go into effect in 2006. This action responded to Governor George Pataki’s call for an RPS program in 2003.
• Under the plan, 25% of New York’s electricity will come from renewable sources by 2013. The state will reach 24% through RPS requirements and will obtain the remaining 1% via green marketing.
• The PSC should issue an Implementation Plan in the first half of 2005.
• The New York Power Authority, the Long Island Power Authority, and municipal utilities are exempted from the requirements, but encouraged to voluntarily participate.
• NYSERDA will procure all renewable power contracts under the program. NYSERDA conducted an initial solicitation for bids and selected the winning bids in February 2005. There is no ACP since NYSERDA will procure the contracts.
• With few exceptions, only projects developed after January 1, 2003 will be eligible for the program. There will be no tradable RECs at first. Power generated out of state can qualify for the program if an associated amount of power is delivered into New York each month.
• The PSC estimates that about 3,700 MW of new renewable generation must be added in the next 9 years to reach 25% renewables.
• The PSC will review the entire RPS program in 2009.
• The PSC wants RPS requirements to give way to a market-oriented program. NYSERDA will file a proposed transition to a market-based system in 2009.
• To participate in the program, renewable developers should contact NYSERDA and the PSC.

Minnesota

• Minnesota’s RPS was amended in 2003. It is mandatory for XCel Energy, which provides over half of the state’s electrical load.
• The program sets good-faith percentage requirements on all retail providers, with the percentages increasing from 1% in 2005 to 10% by 2015.
• XCel’s share of the good-faith percentage requirements is mandatory, does not include power attributable to prior mandates (a total of 935 MW required to be obtained from wind and agricultural biomass sources by 2002), and includes a requirement to generate or procure an additional 300 MW of wind power by 2010.
• The Minnesota Public Utilities Commission has issued a series of orders implementing the statutory program. It has opened a docket to determine whether the program will include tradable RECs.
• It is uncertain how strong the non-XCel good-faith program will be. There are no penalties for non-compliance as yet, but the PUC seems to be serious about implementing the good-faith program and requiring compliance.
• To participate in this program, renewable developers should start by contacting the Minnesota PUC.

New England

• New England can generally be considered as one market, since projects either located in or delivering power into ISO-NE territory (most of New England) are potentially eligible for any of the Massachusetts, Connecticut, Rhode Island, or Maine RPS programs.
• The Massachusetts and Connecticut programs are two of the most advanced RPS programs in the country, with ambitious percentage requirements, already-functioning REC markets and significant penalties for non-compliance. Rhode Island’s recently enacted program should be similarly strong when it takes effect in 2007.
• Maine’s program offers little opportunity to new renewable projects because existing projects satisfy its percentage requirement.
• Eligibility requirements for the four New England programs vary, so a particular project may qualify for one program but not another.
• According to Evolution Markets, Massachusetts RECs for 2005 are trading in the $40 to $50 range, while Connecticut Class I RECs for 2005 are trading in the $35 to $45 range.
• Together, the Massachusetts, Connecticut, and Rhode Island programs will cause significant additional renewable generation to be installed. The proposed Cape Wind project (420 MW), if developed, may affect the New England REC market.
• To participate in the Connecticut or Massachusetts programs, renewable developers should register with the Connecticut Department of Public Utility Control or the Massachusetts Division of Energy Resources, respectively. To participate in the Maine or Rhode Island programs, developers should contact the Maine Public Utilities Commission or the Rhode Island Public Utilities Commission, respectively. To participate in any of the programs, developers should also contact NEPOOL to register in the NEPOOL GIS.

Texas

• The RPS statute sets statewide targets for MWs of new renewable generation—800 MW by the end of 2004, 1,400 MW by 2006, and 2,000 MW by 2008. ERCOT administers the program and converts the targets into megawatt-hour–based requirements for each retail electric provider.
• Only new generation (installed on or after 9/1/99) qualifies for RECs, but older renewable plants may qualify for offsets that reduce the purchaser’s share of overall state renewable purchase requirements.
• Out-of-state power may qualify for RECs under the Texas program, but subject to difficult restrictions, so no out-of-state power has actually qualified so far.
• According to Evolution Markets, Texas RECs for 2004 are trading in the $13 to $15 range.
• Over 1,200 MW of new renewable generation was online as of 8/04, easily meeting the 2004 target of 800 MW. Over 95% of the new projects to date have been wind projects. The program’s success means that less than 800 MWs of new generation remains to be added by 2008 to meet the statutory requirement.
• The Texas Energy Planning Council may recommend that the Texas legislature establish a new RPS requiring 5,000 MW of installed renewable capacity (including 500 MW of solar) by 2015 and 10,000 MW of renewable capacity by 2025.
• To participate in this program, renewable developers must register with the Public Utility Commission of Texas and with ERCOT.

Next Best Opportunities
Colorado

• The program was passed by ballot initiative in November 2004. It requires Colorado utilities with 40,000 or more customers to meet a threshold of 3% renewables from 2007 through 2010, 6% from 2011 through 2014, and 10% in 2015 and thereafter.
• The program will include tradable RECs. Power generated out-of-state may qualify for the program, but power generated in-state will be given greater weight toward compliance.
• The Public Utilities Commission of Colorado will adopt implementing regulations by March 2006.
• An affected utility can exempt itself out of the program if it holds an election and a majority of its customers approve exemption. Similarly, unaffected utilities can opt into the program.
• According to the Union of Concerned Scientists, the Colorado RPS will cause nearly 1,300 MW of new renewable generation to be built by 2025.
• To participate in this program, renewable developers should contact the Colorado PUC.

Nevada

• Nevada amended its RPS statute in 2003. It was first enacted in 2001. The Nevada PUC finalized new implementing rules early in 2004.
• Retail electric providers were required to have 5% renewables in 2003–04, increasing by 2% every other year up to 15% in 2013. There is a set-aside for solar power.
• The program includes tradable RECs. Power generated out-of-state might qualify for the program if delivered to a provider’s lines and if approved by the PUC.
• In 2003, Nevada’s two major utilities were unable to meet the portfolio requirements because renewable developers had trouble obtaining financing due to the utilities’ poor credit rating. At the initiative of Governor Kenny Guinn, in September 2004 the Nevada PUC adopted rules creating a ratepayer-funded trust dedicated to paying renewable projects for their power and RECs.
• Nevada’s RPS will cause the installation of significant new renewable generation in the state. Many more renewable projects could be developed in Nevada with the expectation of exporting power to California.
• To participate in this program, renewable developers must apply to the Nevada Public Utilities Commission.

New Mexico

• In March 2004, Governor Bill Richardson signed into law an RPS bill replacing an initial RPS program developed by the state Public Regulatory Commission (PRC).
• In July 2004, the PRC issued proposed rules implementing the RPS statute. These rules have not yet been finalized.
• Utilities must have at least 5% renewables by January 1, 2006, increasing 1% each year up to 10% by January 1, 2011. The program will include RECs, probably tradable.
• Governor Richardson and others believe that New Mexico can not only generate a significant portion of its own power needs from renewable sources, but also export renewable power to other western states.
• To participate in this program, renewable developers should start by contacting the New Mexico Public Regulation Commission.

Other Opportunities—Key Features
Hawaii

• Hawaii amended its RPS statute in 2004. It requires utilities to meet renewable percentage requirements from 7% in 2003 to 20% in 2020.
• By December 31, 2006, the Hawaii Public Utilities Commission must develop and implement a ratemaking structure that incentivizes utilities to cost-effectively meet the RPS. The structure will allow for deviation from the standards if they cannot be met in a cost-effective manner.
• The PUC may give a utility temporary relief from the standards if it is unable to meet the standards in a cost-effective manner.
• To participate in this program, renewable developers should start by contacting the Hawaii PUC.

Arizona

• Arizona’s RPS program went into effect in 2001 and is applicable to all retail providers. The final threshold is a relatively modest 1.1% renewables in 2007, 60% of which must come from solar electric power.
• Present requirements will cause the installation of a relatively small amount of additional renewable generation, largely solar.
• Arizona’s political leaders talk about increasing the state’s commitment to renewable power, especially solar. Governor Janet Napolitano advocates a state commitment to solar energy. Some members of the Arizona Corporation Commission want to increase the state’s RPS requirements, though others oppose it.
• To participate in this program, renewable developers should start by contacting the Arizona Corporation Commission.

Wisconsin

• Wisconsin requires its utilities to have portfolios including increasing but relatively modest percentages of renewables. The program-tradable RECs that can be banked.
• Utilities have already banked enough RECs to meet the final statutory threshold of 2.2% renewables in 2011, so there is little incentive to develop new projects under present law.
• A task force appointed by Governor Jim Doyle is expected to recommend that utilities meet renewable portfolio requirements of at least 10% by 2015 and that state agencies purchase 10% renewables by 2006 and 20% by 2010.
• To participate in this program, renewable developers must certify their facilities with the Wisconsin Public Service Commission.

Iowa

• Iowa requires its utilities to collectively generate 105 MW of renewable power statewide.
• This standard is already met through existing wind and biomass projects, so there is no meaningful incentive for new projects under present law.
• To participate in this program, renewable developers should start by contacting the Iowa Utilities Board.

No Opportunity Created Yet
Illinois.

• At present, Illinois simply has renewable goals in the context of an overall energy security initiative. No rules have been adopted to achieve the goals. The Illinois Commerce Commission is considering an RPS Plan submitted by Governor Blagojevich.

Future Opportunities

• More RPS programs may develop in the West. Governors of 13 western states making up the Western Governors Association have committed to support accelerated development of 30,000 MWs of renewable resources throughout the West. Some of these states may enact mandatory RPS programs in the future, while others may rely on voluntary RPS programs, net metering, or green power marketing. Some states may emphasize exporting renewable power to large-energy-consumption states like California. WREGIS is scheduled to be operational sometime in 2005 and will be available to verify renewable generator information. Individual states will decide whether to include tradable RECs in their programs and whether to use WREGIS as their system administrator. Growth opportunities for renewable projects in the West will hinge on two critical factors: (1) whether or not WREGIS functions effectively, not only as a collector and verifier of renewable generator information, but also whether or not states choose to use it as a tradable REC platform, and (2) whether or not California continues its course toward an ambitious RPS program and ultimately implements a tradable REC program that includes projects in other western states.
• Other jurisdictions in the northeast (e.g., Delaware) might develop RPS programs in the next few years.
• Development of wind generation has taken off in many midwestern states. In 2004, RPS bills were introduced in several midwestern state legislatures. Some policymakers in these states are interested in RPS programs, but there is also widespread skepticism of mandatory requirements.
• Few southeastern states, excepting Florida, have shown interest in enacting RPS programs.
• Some states that have satisfied or soon will satisfy their existing requirements (e.g., Texas, Maine, Arizona and Wisconsin) might increase their requirements, as New Jersey did this year.

Effect of Extension of Section 45 Production Tax Credits on RPS Opportunities
In October 2004, President Bush signed into law two bills extending the availability of production tax credits under Section 45 of the Internal Revenue Code. The first extended the Section 45 credit for wind, poultry waste, and closed-loop biomass projects. The second made Section 45 credits available to eligible solar, wind, geothermal, small irrigation power, open-loop biomass, landfill gas, and municipal solid waste facilities. The new Section 45 credit will create an additional benefit for projects that qualify for an RPS program. Developers that qualify for the Section 45 credit could have a price advantage in states with competitive bidding.

Conclusion
State RPS programs have created significant opportunities for renewable project developers to increase their returns through price premiums. In some states, RPS programs may be more beneficial than Section 45 tax credits. Many projects may qualify for more than one RPS program. To take full advantage of the opportunities offered by RPS programs, developers should review the full range of available programs and consider their options before deciding where to develop and where to sell power and RECs. DE

CHARLES G. WILLING Jr. Esq., of Ralph, Young, and Pignatelli, specializes in energy development and environmental compliance.

1 These programs are Arizona (Ariz. Comp. Admin. R. & Regs. R14-2-1618), California (Cal. Pub. Util. Code §§381, 383.5, 399.11–399.16 and 445, Calif. Pub. Res. Code §§ 25740 – 25751), Colorado (Colo. Rev. Stat. §40-2-124), Connecticut (Conn. Gen. Stat. §§ 16-1, 16-245a, Conn. Agencies Regs. §§ 16-245-1 – 16-245a-2), District of Columbia (Council Act No. 15-755, Bill No. 15-747), Hawaii (Haw. Rev. Stat. ch. 269), Illinois (Ill. Rev. Stat. ch. 20, para. 688), Iowa (Iowa Code §§ 476.41 – 476-45, Iowa Admin. Code r. 199-15.11(476)), Maine (Me. Rev. Stat. Ann. tit. 35-A, 3201, 3210, Me. Code R. § 65-407-311), Maryland (Md. Pub. Util. Code Ann. §§ 7-701 – 7-713), Massachusetts (Mass. Gen. Laws Ann. ch. 25A, § 11F, Mass. Regs. Code tit. 225, §§ 14.01 – 14.22), Minnesota (Minn. Stat. Ann. §§ 216B.1691, 216B.2423, 216B.2424, Minn. Pub. Util. Comm'n, Orders dated Jun. 1, Aug. 13 and Oct. 19, 2004), Nevada (Nev. Rev. Stat. §§ 704.7801 – 704.7828, Nev. Admin. Code §§ 704.8831 – 704.8893), New Jersey (N.J. Stat. Ann. § 48:3-87, N.J. Admin. Code § 14:4-8), New Mexico (2004 N.M. Laws ch. 65, N.M. Admin. Code § 17.9.572), New York (N.Y. Pub. Serv. Comm'n, Order Regarding Retail Renewable Portfolio Standards, Sept. 24, 2004), Pennsylvania (SB 1030, 2004), Rhode Island (R.I. Gen. Laws §§ 39-26-1 – 39-26-10), Texas (Tex. Util. Code Ann. § 39.904, P.U.C. Subst. R. § 25.173), and Wisconsin (Wisc. Stat. §§ 196.377 – 196.378, Wis. Admin. Code §§ PSC 118.01 – PSC 118.06).

Some observers list Illinois as having an RPS program because the Illinois legislature has articulated renewable power goals. However, no steps have been taken to achieve the goals. As of March 2005, the Illinois Commerce Commission is considering an RPS plan proposed by Gov. Rod Blagojevich.

2 Section 45 has applied to wind and "closed-loop biomass" projects for over 10 years and to "poultry waste" since 1999. The newly enacted federal tax law (the "American Jobs Protection Act of 2004", P.L. 108-357, October 22, 2004) expands the section 45 production tax credit to include sources such as solar, landfill gas, waste wood, and trash. The value of those credits is $0.018/kWh ($18/MWh) for wind, $0.009/kWh ($9/MWh) for landfill gas. By comparison, the current market rate for RECs in New England is in the $35–$45/MWh range.

3 States have also developed other types of programs to encourage renewables, including funds dedicated to renewable energy projects, green power marketing and customer choice programs, streamlined siting rules, tax incentives, and net metering. Voluntary markets have also developed. Those programs and markets are outside the scope of this article.

4 The theory is that increased demand for renewable power will create economies of scale, accelerating a cycle in which renewables will become more economic.

5 The US Senate passed energy bills requiring that 10% of the nation's electricity come from renewable energy sources by 2020 in 2002 and 2003. In both years, the House did not agree to such a measure. A renewable portfolio standards bill has been introduced in the US House once again in 2005.

6 Electric service providers (ESPs) must comply with the California RPS starting in 2006. The California Public Utilities Commission is considering how to implement the requirements with respect to ESPs.

7 These states are Arizona, California, Colorado, Connecticut, District of Columbia, Hawaii, Maine, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, and Wisconsin.

8 Maine utilities already get over 40% of their load from renewable power (as defined under Maine's RPS program).

9 Iowa requires its three investor-owned utilities to have a total of 105 MWs of renewable generation capacity statewide (this responsibility is divided among the utilities) and the requirement is being met with current capacity.

10 At present, California's RPS program does not provide for tradable RECs. "Environmental attributes" must be sold together with the corresponding electricity to the load-serving entity, and then retired.

11 In New Jersey, the Board of Public Utilities will set the ACP each year at a level greater than the anticipated market price for RECs. For 2004, the BPU set the ACP for RECs for Class I and Class II resources at $50/MWh and for solar RECs at $300/MWh.

12 In New York, Administrative Law Judge Stein recommended in her Recommended Decision dated June 3, 2004 that the PSC adopt a penalty in the amount of 150% of the prior year's certificate cost. The PSC did not decide on penalties in its order of 9/24/04, but presumably it will eventually adopt a penalty scheme substantially similar to ALJ Stein's.

13 e.g., Maine (up to 100 MW), and Minnesota and Wisconsin (both up to 60 MW).

14 e.g., Iowa, Minnesota.

15 e.g., California, Connecticut, Hawaii, Maine, Maryland, Massachusetts, New Jersey,

New York, Rhode Island, Texas, and Wisconsin.

16 e.g., Maryland.

17 e.g., Nevada, New Mexico.

18 e.g., California, Nevada, New York.

19 e.g., California, Connecticut, Hawaii, Maine, Maryland, Massachusetts, New Jersey,

New Mexico, New York, Rhode Island, and Wisconsin.

20 e.g., Arizona, California (conversion plants and older combustion plants), Connecticut, Hawaii, Iowa, Maine, Massachusetts, Nevada, New Jersey, and Pennsylvania.

21 Wind-generated projects installed on or after 1/1/04 receive 120% credit toward RPS requirements for output generated by 12/31/05 and 110% credit for output generated between 2006 and 2008.

22 Other states with vintage requirements include Arizona (January 1, 1997) and Wisconsin (January 1, 1998). Rhode Island limits the amount of existing (operating prior to December 31, 1997) that can be used to satisfy its RPS.

23 SEPs are paid from a CEC-administered trust funded by charges collected from ratepayers. The SEP payments are intended to insulate power purchasers from above-market costs in their procurement of renewables. New or repowered MSW plants are not eligible for SEPs. New or repowered biomass plants must meet fuel use specifications to be eligible for SEPs.

24 e.g., California, Colorado, Maine, Maryland, Massachusetts, Minnesota, Nevada, New Jersey, New York, Pennsylvania, Rhode Island, Texas (though limited), and Wisconsin.

DE - May/June 2005