Comments from Ryan Wiser, Lawrence Berkeley National Laboratory:

In general, I believe this is an excellent report, and I agree with the vast majority of the recommendations and their prioritization.

General Comments

1. The cost analysis assumes an incremental cost of renewable energy of 2.5 cents/kWh. Given recent and projected trends in wholesale power markets, I suspect that this estimate is high, perhaps substantially so. California has not had to pay more than 1.5 cents/kWh over a 5-year period, while new wind in Texas is coming in at little if any premium at all. At the least, I would identify a scenario where costs are considerably lower.

2. Overall, the report needs considerable updating. AZ and NM both now have RPS policies. CA's SBC has been extended an additional 5-10 years. (I can provide more thorough updates on RPS and SBC policies, if desired.) Wholesale power prices have risen considerably. Natural gas prices are uncharacteristically high, exactly the opposite of what the report says when it claims that natural gas prices are at all time lows. The description of experience with tracking systems on III-22 is also out of date, as are numerous other details throughout the report.

3. On report structure, I would recommend that Section II precede Section I. Providing a definition for renewable energy would seem to logically precede providing data on renewable generation and supply.

4. I did not read the Appendix A in any level of detail, but I believe it should be reviewed closely by state expects. The California write-up, for example, needs updating. Additionally, it is not true that the IOUs have sold most of their generation. They have sold quite a lot, but not yet "most" I believe. Also, SDG&E has not completed all of its stranded cost recovery. Though this is conventionally believed, SDG&E customers will be paying stranded costs for another 20 years for old QF contracts.

5. Also in Appendix A and Appendix B, I believe the report mischaracterizes the state "definitions of renewable energy." States have established definitions for renewable energy sources eligible for various state policies. The important point here is that states have helped define "eligible renewable energy" not "renewable energy" per se. California legislators certainly realize that large hydro is renewable, they just did not find it necessary to further subsidize the resource.

6. I would not use the distinctions between "financial incentives" and "actions to improve market efficiency." I would argue that "financial incentives" are also actions to improve market efficiency, so to me the distinction is not a valid one. Maybe the term "other actions to improve market efficiency" would be sufficient.

7. Though the report indicates that experience with the policies covered will be provided, the report offers very little of that experience. For example, early experience with the TX RPS might usefully be offered, as with the CA SBC, etc. Similarly, a number of local, state, and federal customers have begun to purchase green power, and yet this experience is not offered. Perhaps such experience is peripheral to the purpose of the report, but it is something to think about…

8. On page IV-2, some detail on the level of recommended SBC's should be provided. 10% and 20% RPS standards have been proposed, and I see no reason why not to establish similar guidelines form state SBC policies.

9. I wonder why CO2 policies at the federal level are not mentioned. While I recognize the political sensitivity of such a policy, it appears to me that a concerted effort on and concern for climate change may be the only way to meet the 10%/20% RE goals.

10. I'm not sure I agree with some of the shading of priorities on page IV-9. For example, a federal SBC should be a priority in my view. Also, continuation of the federal PTC should have the highest priority, in my view - states will be far more reluctant to establish sizable RE policies without this incentive being in place. I also disagree that adoption of NAAG guidelines is somehow necessary or even useful for the development of the green market. I know many who believe that the NAAG guidelines may do more to hurt the market than to help it. This concern should perhaps also be addressed elsewhere in the report where relatively high priority is given to this recommendation. I'm also not convinced that SO2 programs should receive such high prioritization. The value of PTC extension far exceeds the value of SO2 programs for renewable energy, as would reasonable transmission rules it seems. Also on this list, I see net metering identified, a policy that had not previously been discussed in the report - a previous mention would be useful. Also, on RTO issues, some of these are addressed on the state level - the CA ISO is a good example. So, you might also shade the state government column for these policies. Again, I also note the absence of CO2 policies in the table.

11. On page IV-17, extension of the 1.5 cent/kWh would be additionally valuable if expanded to include standard biomass and geothermal facilities. I believe this should be a recommendation that AP2 should consider.

Detailed Comments

1. In the first section, the text should note that the first table identifies those states that have enacted restructuring legislation, not "whether each state's electric utility industry has been restructured to allow for retail competition." The time between passing restructuring legislation and actually implementing retail choice has been demonstrated to be considerable in several Southwestern states.

2. "Planned renewables capacity" in the table on page I-5 is quite sketchy. Colorado has plans to add some 20-30 MW of wind if I am correct, and it is clearly not included. Nevada is listed as planning 260 MW, but I am aware of any policies in Nevada that will provide sufficient incentives for that development. In general, I believe these data points come from REPiS, a useful database but also one that does a very poor job at capturing planned activities in a comprehensive and consistent manner.

3. The table on page I-6 may also need some checking. California is listed as having 18.9% renewable energy generation. This is certainly not true if one excludes hydro. Does the table include hydro? And if so, it does not seem consistent to exclude hydro in the capacity column but include it in the energy column.

4. The cost data on I-13 is a bit confusing to me. In particular, I'd like to know why the cost of GENCO financing and IPP financing differ? IPP's are often Genco's and vice versa - I see no reason for cost differences to exist between these two categories.

5. On page III-3, under the RPS description, the text claims that RPS programs generally include a cost-capping mechanism. This is simply incorrect. It is possible to include a cost cap, but as a practical matter very few states with an RPS have established such a cap.

6. On page III-3, under tax incentives, I'd like more detail on what you mean by "personal and corporate income tax credits." The PTC is such an incentive. Perhaps you mean "personal and corporate investment tax credits…"

It is difficult to analyze the details of the Forum's proposed plan due to two underlying assumptions that have apparently been missed or ignored that will have a large impact on the reality of achieving the 10/20 goals.

The goals of 10% and 20% of the western states energy being derived from renewable resources is indeed an admirable one, however, the economics provided in the proposal are significantly incomplete.

The first issue that I would take is with regard to energy transmission and the second is with regard to the non-firm nature of the renewable energy source being contemplated.

No matter what type of resource is used for the renewable generation it is extremely unlikely that the source will be conveniently located near to an already existing transmission system, switch yard or sub-station. The proposal accepts this fact but merely glosses over the cost and acceptability of providing suitable transmission by passing that burden on to some other entity. When a new, traditional, thermal, generation station is planned, the location of the new generation site is a major consideration because of the high cost of providing new transmission access and the difficulty in obtaining planning permission for new transmission lines. Only in exceptional circumstances would a new generation facility not be located in close proximity to an existing transmission system access point. I feel, therefore, that the provision of suitable transmission facilities is a major integral component of the program and to ignore the potential cost of providing adequate transmission is a major omission from the proposal.

The issue of the non-firm nature of renewable energy is perhaps a greater and the most fundamental omission from the proposal. Unless the renewable resource is gas based, such as from landfill methane or biomass, (and I would include geothermal in this aspect,) the very nature of the resource produces non-firm energy. Typically, a utility will have access to between 12% and 15% spinning reserve to ensure generation reliability. This suggests that if the non-firm component of the generation mix exceeds maybe 3% that conventional thermal generation plant will need to be available to provide reliability backup. My understanding of the economic part of the proposal is that the cost of the wind generation (I believe wind was the main contender) would be seen as an incremental cost over the cost of traditional generation that would have needed to be installed anyway. In light of the requirement to provide backup generation, the bulk of this traditional generation base will ned to be installed in addition to the wind base making the economic analysis erroneous. The concept of 10% or 20% of energy being derived from solar or wind generation may be accomplished at some time in the future, however, energy storage technologies will have to be developed to change the non-firm nature of those resources to firm if the utility companies are to be able to provide reliable energy to their customer base without the need to duplicate generation capacity in the form of backup.

Thank you for giving me the opportunity to review the AP2 Forum Renewables Report. It is obvious that many hours of hard and detailed work have gone into this draft. I believe it will be a very timely and useful resource for state governments, not only those in the GCTVC region, but across the country as they address the problems of regional haze and particulates.

I have provided below a few comments and questions from my reading of the draft. Most are minor, as the quality and depth of information in the draft document, based on availability, is excellent. I hope that as additional information is developed and becomes available, for example on the cost and benefits of renewable resources, that it can be incorporated into the report on an ongoing basis.

I will be happy to discuss my comments or questions with you in further detail. Please contact me at (703) 750-6401, ext. 226 if I can be of assistance.

Section I

Items 2 and 3, and 4

For production information, you may want to look at EPA's E-GRID database, which lists information on renewable generation by state, by plant, by power pool, etc. For a given year (1997 is the latest year of data, I believe) it shows the MWh of generation by renewable power type. It does not provide any forward projections, however.

Item 5

It would be helpful to have a copy of the New England states tracking system attached as one of the appendices or to include a reference to a web site where it can be found.

How will the tracking system determine where renewables are consumed (re grid-connected renewables)? Or does this really mean it will track who is buying grid-connected renewables or where they are being purchased and in what quantity?

When do you anticipate this information will be developed or start to be developed?

What kind of incentives could be offered to consumers or businesses that have incorporated non-grid renewables to report into the tracking system?

The tracking system will be a useful tool. However, it will also be important to offer guidance and/or tools to states to assist them with developing the projections of what their contributions to the 10/20 goals will be, since a forward projection will be required in the SIP. Is the AP2 Forum looking at developing such guidance or a model that states can use?

Item 6

Emissions cap and trade is not the only means for providing incentives to go beyond compliance. A number of states are developing permit streamlining mechanisms, as an incentive for businesses that go beyond compliance. New Jersey has implemented their Gold/Silver track, and Wisconsin is in the process of developing their Green Tier programs. And EPA is initiating its Performance Track program, which operates on the same principle.

Another possibility is to develop environmental management systems (EMS) that are focused on energy systems and use. EMS programs are generally designed to go beyond compliance, and a focus on energy efficiency provides an added incentive in terms of significant cost savings.

Item 8

Item number 8 seems to refer to identification of remote areas that currently lack adequate power supplies and where renewables may be the most cost-effective option. The information provided in the document does not seem to respond to this.

Item 9

It may be useful to include a scenario comparing renewable energy to the estimated price of electricity from generating plants that are no longer grandfathered from CAA requirements and must have adequate controls. EPA and individual states are looking at how to deal with the grandfathered generation problem, and could take action that would make these plant have to comply with the CAA, become subject to NSR, etc.

Section II

This looks very good. The definition provides a broad-based interpretation that provides appropriate limits to allow a large set of technologies to fit under the definition of "renewable." It seems to avoid a narrow, technology-specific focus that might preclude new kinds of renewable technologies from qualifying.

Section III, A

1. RPS and 2. SBC

1.a. Think about the possibility of applying an RPS to other specific market segments, such as:

• Commercial sector non-grid renewables
• Residential (builders) sector non-grid renewables
• Federal-state non-grid renewables

Make these credits interchangeable with the grid-connected, large scale RPS credits.

One way to possibly address the costs and benefits issue for the RPS and SBC is to see if an estimate can be made for the avoided cost of compliance for a kWh/MWh of renewable electricity versus that for fossil-generated electricity. I am unaware of any work that may have been done in this area, but there have to be compliance cost estimates for EPA's rules that could provide some information that may be useful in this regard. Of course, this has no bearing on grandfathered plants, so that may negate the compliance costs factor attributable to newer generation or to NSR improvements.

4. Opportunities for Government Purchasing of Renewables

This section suggests that states could use savings from existing DSM programs to offset the additional costs of purchasing renewable power. It might be helpful for states to have an understanding of how much their DSM savings could buy, if used to offset the additional cost of wind, solar or some other renewable technology. Therefore, an example of what a given state's annual DSM savings could buy in terms of kWh at the current premium for a renewable source, say wind, could give them some idea of how much they could contribute to the 10/20 goal if they follow this recommendation.

A variation on the DSM idea is to construct an ESPC for state agencies that provides for a small amount of the savings to be used to fund renewables. This may mean it would take a little longer for the contractor to recoup their investments, but that might only be a small impact if the percentage the state skims off is very small.

If state government agencies were to aggregate their renewable energy purchases, what effect might that have on lowering the premium?

A state may also be able to establish a voluntary consumer contribution mechanism to a fund (as a supplement to an RPS or SBC) on utility bills. The voluntary contributions could then be used to offset the premium for renewable power for state agencies or schools, or could fund non-grid applications.

Section III, B

4. SO2 Cap and Trade System

One of the reasons for the small usage of the CRER that provided bonus allowances for efficiency and renewables is that the allowances were only made available to the electricity generators that were regulated sources. These allowances could not be offered to third parties for the installation or purchase of renewable resources.

Other similar policies include the energy efficiency and renewable energy set asides that New York, New Jersey and Massachusetts are including in their NOx Budget Trading Programs, which become effective in 2004.

Under the section on further work, it will be necessary to develop a renewable energy allocation mechanism that will work within the scope of an SO2 trading program.

As a final, general comment, it would be useful to provide model rule language (for RPS and SBC, for example), policies and other tools to make implementation of these recommendations as streamlined as possible. Where these examples currently exist, they should be appended to the report or made available on the WRAP website.

Thank you for the opportunity to review your draft report. It clearly reflects a significant effort on your part, and will be a contribution to the policy dialogue at both Federal and State levels.

In general, we agree with the general conclusions of the report that renewable energy is an important part of a clean air strategy. Renewable technologies can supply significant energy to the Western States at a reasonable cost with appropriate policy support. Your estimates of the potential renewable contribution are probably conservative, particularly because the modeling does not adequately account for geothermal energy resources. Moreover, your cost estimates are probably high given the potential for geothermal energy to contribute to the mix.

As you know, the U.S. Department of Energy has initiated a program known as "GeoPowering the West." The goals of this initiative are to achieve:

• 10% of the electricity used in the western states by 2020
• 7 million homes using geothermal energy by 2010 and
• Double the number of states with geothermal facilities to 8 by 2006

A broad range of policy strategies are being pursued in this initiative, policies that parallel those proposed in your WRAP report. According to DOE its initiative would provide Federal leadership in Education and outreach, technology development, policy and institutional support and state, tribal, and local partnerships

The Department has enumerated what it believe the benefits would be of achieving the goals of GeoPowering the West. They benefits would be:

• $50 billion in capital investment in the western states over 20 years
• $500 million in new income for western landowners over 20 years
• $5 billion in annual capital investment in 2020
• 20 million tons of atmospheric carbon displaced in 2020

Of course, significant SOx, NOx and particulate pollution would also be avoided by this level of geothermal energy production in the West.

The potential of the Western States is significant. DOE sees future electricity production potential in the producing states Nevada, California, Utah and Hawaii, but also envisions new geothermal production in New Mexico, Idaho, Oregon, South Dakota, Texas, and Wyoming. In addition to electricity production, all of the Western States have significant, untapped potential to displace fossil fuel energy through the direct use of geothermal energy for commercial and residential applications. In the West, some 300 cities and towns have been identified within 5 miles of a known geothermal resource. A database of 9,000 sites has been compiled by the Geo-Heat Center at the Oregon Institute of Technology.

Perhaps most significantly, your study recommends some important policy initiatives to support geothermal and other renewable energy development. I would recommend that you also consider supporting initiatives by the US Department of Energy, such as GeoPowering the West and Wind Powering America. These efforts have been important and deserve your support. In addition, I would make the following comments on your policy proposals.

Policy framework

I would encourage your support of the following policy proposals:

1) Extension of the Production Tax Credit

We would encourage your group to include as a high public policy priority the extension of the existing production tax credit. No only should its current termination date be extended, but its should be expanded to produce the same tax credit to all renewable energy resources.

Production Tax Credit Background

Section 45 of the Internal Revenue Code provides for a "production tax credit" for electricity produced from new facilities using wind energy and closed-loop biomass resources. However, due to the stringency of the definition for biomass facilities, the tax credit has exclusively benefited the deployment of wind energy facilities. The Energy Policy Act of 1992 extended the credit, but failed to extend its effective coverage beyond wind technologies.
As Congress stated in 1992, "The Credit is intended to enhance the development of technology to utilize the specified renewable energy sources and to promote competition between renewable energy sources and conventional energy sources." Today, there is a need extend the credit all renewable electric technologies to encourage their utilization, and ensure fair treatment of renewable technologies.

Wind, solar, geothermal, biomass and some hydropower have significant environmental advantages over fossil fuels. They provide benefits to society in terms of energy security, improved environmental quality, better public health, and other ways. Many of these benefits, however, are not reflected in the market-price of electricity and this market failure should be corrected by the extension of a tax credit to qualifying renewable resources as described below.

This credit will also allow these renewable technologies to compete on a more even footing with conventional fossil, fuel technologies. Solar, wind, geothermal and biomass are all slightly higher in their first cost than conventional sources, and generally have a higher risk for investors. A production tax credit will enable the renewable industries to continue to develop and mature their technologies and drive down costs while providing Americans with more clean, emissions-free electricity generation

Proposal

As a means to promote the deployment of renewable electricity generating technologies, the following should be proposed by the next Administration and adopted by Congress as a permanent part of the tax code:

Production Tax Credit
There should be a tax credit of 1.7 cents/kwh for first ten years of electricity production from new renewable energy facilities, generally following the terms of the existing Wind Energy Production Tax Credit.

2) Renewable Production Standards should be considered on a broad scale, and without prejudice

Moreover, all RPS proposals should avoid picking and choosing technologies. The concept of the RPS is to allow renewable technologies to compete for a specific market share, and thereby encouraging production from the most cost-effective facilities. In effect, the market place decides. This has obvious advantages to proposals that rely upon government agencies to predict the best technology. However, there has been a tendency in many states to provide special treatment to what is apparently a preferred technology, often on political grounds. This only defeats the purposes of choosing the RPS approach, and will weaken the results of your policy initiatives in providing clean air to the citizens of the West.

Development of geothermal, wind, and other renewables in the West are being held up by slow regulatory decisions, particularly when facilities involve federal lands. For geothermal energy this has become a very serious problem. On some federal lands where geothermal development is preferred by land use plans, decisions have been taking more than a decade. In other areas federal lease applications have been languishing for nearly as long.

Recently, the State of California adopted changes to its laws to provide for faster processing of regulatory actions, and the Governor has assembled a team in his office to assist agencies in making decisions in a timely manner. This does not mean changing laws or regulations in any substantive manner, but it does mean making timely decisions through an orderly and transparent process.

4) Interconnection of renewable energy sites needs special attention

1. Overall, I found the report balanced, fair, and substantively complete. The conclusions and recommendations are supported by the analysis, are practically stated and realistically described. However, my strongest concern is that I found discussion of the potential benefits of energy efficiency to be greatly understated. I know the report is focused on renewables. But renewables are much cheaper to buy in an energy efficient economy. And market penetration levels would substantially increase if the total energy system were both more efficient and cleaner. I am not aware of whether there is an efficiency report that parallels this one. If there is, I would hope there would be a strong synthesis document. Also, we at RMI have been heavily focused on distributed energy resources (right sized supply, efficiency and management resources). We are very convinced of the economic, financial, planning and other benefits of right sized energy resources. However, these solutions face many real obstacles - interconnection terms, etc. Texas has done a good job setting up distributed generation-friendly policies.

2. I am concerned that a non-discerning reader will treat the report like a shopping list, especially in the detailing of recommendations. The interplay between several issues is critical, especially in the context of state restructuring legislation. For example, Colorado's good green pricing programs are being held back by a reluctant dominant utility; only real competition would break that stranglehold. The point is that you may consider a strong section early on about how several issues are related to the context in which they might be implemented. This is even more critical with many policy makers becoming very suspect of the merits of restructuring.

3. I did not see any discussion of one important risk associated with the RPS approach - that a legislature could adopt a very low RPS level in the process of compromise that inevitably leads to such measures. In such a case, you would find yourself having to go "back to the well" for policy measures to advance your goals. There are potential market impacts from a too-low RPS as well. Of course, the SBC has the same kind of risk - if set too low, it might never stimulate sufficient market development to fully commercialize renewables. There are various things that could be done to try to mitigate such concerns - for example, an SBC could be distributed in an auction format that would buy more renewables as prices dropped. Or an RPS could ratchet upwards in future years.

4. I am very concerned at the automatic recommendation of acceptance of the NAAG guidelines. As a veteran of that process, I am very concerned the guidelines are being used as a stick against green markets without parallel concern for the behaviors of non-green marketers, who often have much greater power. For example, in Pennsylvania, PECO continues to argue that they are "the clean energy leader" while green marketers face detailed scrutiny for every ad. What is needed is broad guidelines for all claims in the emerging electric markets. Attached is a summary of the much more market-friendly FTC guidelines.

5. You do not mention one of my favorite programs - the Green-e and the Green Pricing Accreditation Program, also run by CRS (I chair these activities.). The point is that when competitive markets are opened (as indicated by the presence of actual competition), programs like Green-e step in an provide consumer protection, labeling uniformity, auditing and verification, and at no real cost to the government. The Green Pricing Accreditation Program stimulates broad stakeholder participation in the accreditation of utility programs and adds needed credibility to utility programs.

6. I may have missed it, but education is critically important. A recent study by the California Energy Commission revealed abysmally low levels of customer awareness. This is surely due to the botched job of customer education that occurred when the market opened (the regulators let utilities administer the programs in spite of the fact that they benefited directly by low switching rates). But the fact remains (see the RAP research at rapmaine.org) that most customers incorrectly assume their power is cleaner than it is, that few are aware of choice, and that fewer still understand the consequences of their choices. Education programs are critical.

7. While I am generally in agreement about the theoretical economic and environmental benefits of SO2 trading, I caution you to recognize that the jury is still largely out on the issue. Phase II is barely in effect. The system failed to drive significant new renewables or efficiency due to the perverse, but politically motivated, impacts of the initial scheme of allocation of credits. Getting the details right in any cap & trade is critical.

8. You should be aware of the rapid development of green tags markets. These offer the potential to significantly reduce the cost of renewables (as you pointed out in the RPS section, by allowing purchase from the best sites) and are not specifically tied to an RPS system. These systems are likely to work better in competitive markets as opposed to green pricing regimes. They necessitate some care about consumer protection concerns, of course.

In all, I reiterate that you have produced a great report. I hope my few thoughts have been helpful.

In general, I think this is a good report. It is generally well written and well organized. There are, however, a few places where I have suggested changes.

I. The primary adjustment I would urge you to make is in your analysis of the cost of these RE programs. I do not believe it is appropriate to assume that RE prices compared to other resources will remain constant over the next 15 year period!

1) RE costs are all going down while all other types of generation are going up. Natural gas prices have taken a very large leap upward during the last year and though those prices may not stay at $6/mbtu, they are not likely to go back down to the all time low levels that were assumed in this report.
2) Almost all other generation has fuel price fluctuations and most fossil fuel generation also faces increased compliance costs of meeting pollution requirements already on the books. RE costs are front loaded into their capital costs (a distinct disadvantage) but as a result, they can be sold at a relatively fixed and stable cost over time while other generation fluctuates with fuel and other influences.
3) Because of the lack of new generation plants in the west, the average wholesale price of power has gone way up. RE may not look bad by comparison in the next few years.
4) In 1998-mid 2000, in the California Green market RE has tended to run 1.5 cents/kWh more than conventional power. You even use that price in your Federal Purchase discussion though you use 2.5 cents/kWh in your calculations.

Other more minor things:

II. RPS Table is missing the Arizona RPS

III. SBC Table is missing Delaware and Maryland (though you discuss Delaware in the text).

IV. RPS and SBC are NOT conflicting programs. In fact, five states (Conn, Mass, NJ, PA and Wisconsin) have passed both SBC and RPS legislation. RPS creates a specific market for RE while SBC creates a pot of money that can be used in any number of ways (e.g. EE, low-interest loans for new RE projects; consumer rebates; some type of support for on-site generation like roof-top PVs; support for RD&D; etc.)

V. Tracking generation and even issuing RECs does not automatically eliminate double counting though it can make it easier to verify what is being sold. Unfortunately, there is the other half of the equation -- "How much demand is being served by how much supply."

VI. Under the Government Procurement discussion, you didn't mention the requirement by most sectors of government that they must purchase the least cost source of the product. Fortunately, we were told by the GSA that having a specific standard for renewables (as is laid out in the Green-e Program) established a whole new product classifications. Before there was just electricity now there is regular electricity and renewable electricity meeting a standard criteria. So Federal agencies can now purchase renewable energy that may cost more than other power as long as they purchase 'least-cost' renewables that meet the specified criteria.

VII. There was no mention of the Green-e program. Though you mention in the green marketing section the benefits of consistant standards, criteria, definitions, disclosure and verification, you never mention the fact that that is the purpose of the Green-e program (for more info see WWW.Green-e.org). Related is the 'Green Pricing Accreditation Program' that has the same elements and purpose but is applied in non-restructured states to Green Pricing Programs. Both programs were designed to provide consumer's assurance that they are getting what they are paying for.

VIII. Finally, in the Transmission section you mention that RE might not actually be able to meet the 10% to 20% targets laid out in the proposal because of system reliability related to intermittancy. First, not all renewables are intermittent -- primarily you are referring to wind and solar. Second, studies by PG&E indicate that the Western grid (and most any other grid that is not too small or isolated) can easily handle up to 15% intermittent power without causing transmission instability. (Talk to Carl Weinberg, former Director of RD&D for PG&E - 925/933-9394.) Third, a more recent report written in Europe (I believe) indicated most large electrical systems can take up to 30 % intermittent power without any problems. All this says that unless you are getting all your power from one source region-wide, your 20% target isn't likely to be affected by transmission reliability problems due to intermittent resources.

• Comments from David Bassett on behalf of Robert Dixon, EERE (pdf Format)
• Comments from Bill Becker, Denver Regional Office (pdf Format)

General Comments

Because the draft final report follows a standard reporting format that results in frequent repetition of information and recommendations throughout the sections of its text, it is important that the executive summary be a readable stand-alone document that includes the complete recommendations. For instance, all of the information under the "States" section of "Priorities Among the Recommendations" (sec. IV) should be in the executive summary.

The draft report correctly identifies the renewable portfolio standard (RPS) and systems benefits charge (SBC) as the two policies that can have the greatest effect in increasing the amount of generation from renewable resources. It is understandable that the Report should recommend the RPS or SBC or both as the key financial incentive for increasing generation from renewable sources. That approach leaves flexibility to states to respond as their policymakers think best. However it is important to characterize these approaches carefully.

There is no reason to suppose that the RPS would be more costly than the SBC approach for an equivalent amount of generation. The draft report states that if an RPS is set right at the 10% and 20% goals, "the costs of imposing such a requirement could be substantial" (IV-1). However, the same is true of an SBC that attains the same 10% and 20% goals. On the assumptions in the draft report, each would cost about $.005/kWh. In no event would the RPS be more costly for equivalent increases in generation from renewables.

In fact, the RPS is in principle a least-cost approach to meeting any given level of renewable generation goal. Suppliers subject to the RPS trade amongst themselves to procure the lowest-cost resources until the standard is satisfied. This point is buried on page III-3 but needs to be made up front. An SBC system can also yield least-cost results, but only if it is effectively structured and administered to fund the lowest cost renewables.

In practice one of the uses of SBCs is often to provide some support for technologies which are still emerging and are more costly than wind power -photovoltaic cells, for example. This point is buried on page III-9 but could be mentioned in the summary. Some say that an SBC is a nice complement to an RPS, since an RPS will encourage near-market-ready renewables while SBC funds can potentially provide support for emerging technologies.

Certainly increasing the amount of generation from renewable resources is likely to cost more in the period through 2015 than not doing so. The draft report is correct in explaining that a regional sulfur dioxide emissions cap-and-trade program would reduce the cost differential between conventional and renewable generation (p. v). But other factors are already at play which reduce the report's "base" differential cost estimates.

In particular, rising gas prices mean that the cost premium would likely be less than the $.025/kWh highlighted in the draft report. The report should look at a case where, for example, gas prices start at $4.50/mBtu and remain constant in nominal dollars. I see little reason to use "conservatively high estimates of differential renewable costs" (p. IV-4) given the strong upward pressures on prices from conventional generation. Additionally, comparing the differential costs of renewable generation to current electric revenues, as is done on page iv, may overstate the relative cost of meeting the 10/20 goals if the costs of conventional generation increase more rapidly.

I do not understand the meaning of the statement that "the least-cost strategy to meet the 10/20 goals is for the western states and the federal government to undertake a major effort to develop the region's wind resources, together with additional cost-effective renewable resources such as geothermal and biomass that may be available locally" (p.iv). What exactly is "a major effort to develop wind resources?" The wind is there. It would seem that the least-cost strategy would be to choose an RPS at the 10/20 level. This statement appears in the summary and in sec. IV. It should be explained or deleted.

As indicated above, the draft report is correct in identifying the RPS and the SBC as the two policies that would have the greatest impact on the amount of generation from renewables. The draft identifies a number of additional policies that would help to reduce market barriers to renewable resources and to create market demand for them. The report's identification and assessment of these policies is in my view sound. However, the speculation that green marketing and green pricing programs could provide 3% of the 20% goal (page iv) should be clarified. If this means such programs may increase generation from renewables by 0.6% of total generation, the speculation is reasonable. If it means that they may cause new generation from renewables equal to 3% of total generation, the experience cited in the report does not support such an optimistic assessment.

Specific Comments

The above are the main comments offered to WRAP. Next a few very narrow comments are offered.

I.1.c, programs currently in place: Colorado and Utah have integrated resource planning rules through which renewable resources can -and in Colorado, have-been added to the resource mix.

I.2/3.c, resource inventory: the regional totals from Appendices E and F would be helpful on pp. I-5 and I-6.

Page I-13, I would think the cost for an IOU lower than for a genco, not higher as is shown here.

It is certainly sensible that "a policy or program should count" as described on page I-16.

Why doesn't WRAP's definition of renewables include chemical fuel cells, at least those not using natural gas? (II-1)

III-3 describes the RPS. Note that large amounts of renewables can be brought into the mix through legislation or regulation that is not in the form of an RPS "percentage." Minnesota and Iowa are among jurisdictions that have accomplished this. These policies should be added to the "RPS Policies Established" table, or a separate table created to display them.

Also on page III-3, it obviously is necessary to update the comment about gas prices being near historic lows.

Further on in the RPS section appears the statement that "RPS by definition has an effect on competition" (III-5). One could also note here that RPS is competitively neutral in that competing suppliers within a jursidiction with an RPS confront the same standards.

III-6: It's true that SBCs are typically volumetric charges. One could also note that in some jurisdictions they are per-customer (IL, WI).

Sec. III B) 2) c, similar policies: I'm not sure whether New England has actually quite "adopted" a single tracking system yet. In any event the basis of the proposed system could be described here (p. III-22).

Sec. III B) 5)'s discussion of siting renewable facilities prompts the question of whether siting of conventional generating facilities offers any levers for renewables: for example including some renewable generation at the site as an offset to environmental harms.

Sec. IV, Estimates of Future Electric Demand: the projected annual growth rate of 1.9% is much too low.

Sec. IV, page IV-15, I'd delete "The impact of property tax incentives on the emerging competitive western electricity system may be no greater than other financial incentives."

Sec. IV B. PRINCIPLE 2: recommendation a. is imbalanced; it recommends that states "should" adopt retail competition but it does not recommend that they retain cost-of-service regulation. This should therefore be rewritten as a recommendation that consumers be provided with means to make renewable product purchases in both regulated and restructured jurisdictions.

Appendix A: several of these descriptions are outdated; perhaps "as of 1999" might be an overall introduction. It's not clear why two Turlock Irrigation District energy efficiency financing programs are included.

This is a great document and could be very useful. I have a few comments that are included below:

1. I'm not sure I agree with your broad statement on the cost premium associated with achieving the renewables goal. With the wind production tax credit in place, and gas having doubled in the past year, wind is now cheaper than gas in Texas and other windy states. Although the PTC is scheduled to expire at the end of 2001, my expectation is that it will be extended at least another 2.5 years. In addition, the cost of wind will only get cheaper in years to come. So there may be a slight premium associated with wind, but it is nowhere close to $4 billion.

2. Green Pricing--Utah Power & Light offers a green product developed by their PacifiCorp parent (p. 11), and PacifiCorp may be marketing such products to areas they serve in the region as well. The "Infinity Wind Energy" electricity product is offered in North Dakota by Minnkota Power to a number of their distribution coops in the state.

3. I presume the statements about the low cost of natural gas will be updated (III-3) and (III-11) and elsewhere.

4. The Texas RPS appears most advanced in its implementation at this point, and is expected to lead to over 700 MW of new wind capacity that will be installed in 2001. The remarkable thing about most of those projects is that they appear to be cheaper than new gas generation. This can be documented from a number of sources, including a press release announcing a new wind project and stating exactly that (cheaper than new gas projects) from the Lower Colorado River Authority based in Austin, Texas. The note on "limited empirical data" ought to be beefed up with more detail on the Texas experience. Many states in the region include wind resources that are as strong as those found in Texas, and thus an RPS shouldn't present much of a cost burden. (III-4-5)

The reason the RPS in Texas has worked is that it really optimizes the cost of wind-it provides long-term contracts for relatively large projects. The Green Market, on the other hand, has relied on relatively small projects developed with only short-term contract support. That is a recipe for high-cost power, and we have seen the absurd result one would expect-PSCo (or ExCel) is asking for a 3.5 cent/kWh premium for its Windsource product while Texas utilities are signing levelized contracts substantially below 3 cents/kWh. Therefore, unless there are changes in the Green Market (longer-term, bigger projects) it will continue to result in projects that are substantially more expensive than optimally-developed renewables. In other words, while we are strong supporters of the Green Market, I hope you will help the reader understand more about the limits of the Green Market. I agree, however, with your 6% Green Market penetration level, and in some ways that says all that needs to be said. I would be glad to provide slides contrasting the cost of a 3 MW project vs. a 50 MW project in the same wind regime.

5. In "Effects on Competition" for the SBC, you state that "The SBC as discussed here is generally more compatible with retail competition in electricity markets. " My question is "more compatible than what?" (III-10) It is hard to say that an SBC is more compatible with retail competition than an RPS, and certainly a comparison of Texas and California wouldn't support such a conclusion. The Texas market for wind is booming due to the RPS, while in California much of the SBC money, although allocated to specific planned projects, has yet to be used because of a variety of barriers in the process. The biggest barrier is not having a power sales contract, and the RPS deals with that head on.

6. The discussion on transmission pricing includes some assumptions I don't share (III-25), although perhaps what you are describing is more specific to the West. Much traditional transmission has been priced on a point-to-point basis, not postage stamp. Much of the movement toward postage stamp is that it is simpler and more compatible with the development of a large regional market.

7. It would be worthwhile to spend some time describing how the RPS and SBC are better suited for some technologies than for others. AWEA supports both mechanisms because we believe the RPS is the best policy to support bulk power renewables in the transition to competitive markets. We support the SBC as a more effective way to support higher cost, non-bulk power technologies such as PV or small wind turbines or energy efficiency (IV-1). I wouldn't want the reader to think that they can choose one or the other when both are necessary to effectively support a range of renewable technologies in the market.

8. "Assuming that the differential cost of renewables is the same in either program" (IV-8) I question whether an SBC is likely to produce the same amount of renewables as cheaply as a well-conceived RPS such as we have in Texas.

9. Why not a federal SBC that could provide matching support for state funds? (IV-9) Certain renewable technologies and efficiency won't be served by an RPS.

10. I don't think wind is more expensive than landfill gas (IV-13) in many locations.

11. You are mixing the discussion of penalties and cost caps for the RPS. There should be a high penalty of at least 2.5 cents/kWh to encourage compliance. Make it clearly more expensive NOT to comply and you will hopefully never have to penalize anyone. The cost cap, on the other hand, is just that-it is an artificial ceiling on the price of RPS credits. If the system works as one hopes, you will never have to rely on the cap-there will be enough cheap renewables available that it makes more sense for companies to acquire real renewables than to acquire credits through the administrator. Thus, the cost cap has value primarily as insurance to deflect the concerns of ill-informed policymakers who fear that an RPS will bankrupt the electric industry. You also want to set the cap high enough that it doesn't short-circuit the market. In other words, with a half cent cap, many companies might opt to acquire credits. With a 1.5 cent cap, you would have fewer but it still might be an issue. We recommend a 2.5 cent cap. (IV-14)

12. You recommend continuation of the wind PTC "until wind becomes cost competitive in the WRAP region." The cost of wind is very site specific and highly dependent upon the wind speed at a site. So if the PTC stays in effect over time it will gradually open up more moderate wind areas to cost-effective development. (IV-19)

13. The 15% limitation on wind's penetration in any region seems overly conservative. There are certainly issues associated with high wind penetration, but an arbitrary cap at 15% is too restrictive, especially given current penetration levels in the Navarre region of Spain and Schleswig-Holstein in Germany which exceed that level. (G-1)