Timing
Several parties, including Calpine, IEP, EPUC/CAC, WPTF, DRA, Environmental Defense, and NRDC/UCS, urge California to move forward without waiting for a resolution of GHG issues at the regional or federal level. These parties urge California to act as a leader in creating a cap-and-trade program for a 2012 implementation date. WPTF argues that deferral of a market-based system would hinder the development of the most efficient emission reduction tool, delay the development of tracking infrastructure necessary for a trading system, and miss an important opportunity to gain experience with GHG trading. NRDC/UCS state that the longer a cap-and-trade system is in operation, the longer it has to reap benefits. It submits that California has an opportunity for leadership to influence regional and federal systems, whereas waiting would relegate California to being "one voice among many at the table." NRDC/UCS stress that, if California adopts a cap-and-trade program with an allowance distribution scheme that does not reward dirty polluters, it would advantage California, as a relatively clean state, if a similar system were adopted nationally.
These parties urge that California should continue working toward a regional or federal system and, to the extent possible, should design its cap-and-trade program so it can transition smoothly into a regional or federal system (IEP, Calpine, Constellation, WPTF, and Environmental Defense).
Other parties that support an eventual cap-and-trade program, including PG&E and SDG&E/SoCalGas, suggest that deferral of a cap-and-trade market structure until it can be implemented on a regional and/or national basis may be desirable. While recognizing that California must proceed with implementing a compliance program regardless of broader action, PG&E states that deferral of a cap-and-trade program may facilitate integration with a subsequent regional or federal program and could yield significant advantages and efficiencies. In PG&E's view, a key integration issue is the transferability of allowances, and an inability to transfer such allowances could cause significant integration issues and be very costly to complying entities and retail providers' customers.
SDG&E/SoCalGas state similarly that deferral is reasonable given the regional/national nature of GHGs. It is concerned that a California-only program could strand investments, particularly if California implements a retail provider-based program but a later regional or national program is source-based.
The CAISO states that it does not necessarily favor immediate implementation of a cap-and-trade system in California. The CAISO states that it is difficult to justify the cost of establishing a sophisticated trading system that might be abandoned soon in the face of federal preemption. It sees advantages to deferring implementation of trading until the form of federal regulation becomes clear. NCPA takes a similar position, stating that it is not important that a cap-and-trade program be adopted in the near term, but that any system adopted in California should allow for a transition to a regional or federal program that does not affect California investments adversely.
Other parties are more cautious about a cap-and-trade approach to GHG emission reductions. TURN recommends that a cap-and trade program not be implemented for the electricity sector in 2012. It states that California would be better served by promoting existing policies that result in real GHG reductions, by developing a comprehensive regional tracking system for GHGs, and by deferring implementation of a cap-and-trade system, pending further regional or national developments.
DRA states that while, on its face, it seems that the electricity sector should be included in a California cap-and-trade program, that is true only if such a program reduces emissions. It views the on-going modeling effort as being critical to answering whether a market-based system is likely to provide additional reductions. DRA submits that deferral of a cap-and-trade program until there is a broader coverage would avoid contract shuffling and leakage issues.
LADWP supports direct regulation as the least-cost approach, with a cap-and-trade program as a secondary method of compliance. LADWP recommends that a California-only cap-and-trade program be implemented only if it can be determined to cost-effectively provide emission reductions equal to those that can be achieved through direct regulation within the same time period, and if further evaluations determine that the market would be robust enough to avoid market power problems.
Parties are divided into three distinct groups regarding how emissions from the electricity sector can be reduced most cost-effectively.
Supporters of a cap-and-trade system believe that alternatives would be less effective. Powerex argues that trading should be a key component because "a cap alone unfairly assumes all emitters have the same cost of compliance, penalizes those that have a higher cost of compliance, and does not reward those that may be able to reduce emissions greater than what is required by compliance through being rewarded by the market for such action." Similarly, SCE suggests that, "Given the significant actions of the electric sector in California to reduce GHG emissions to date, it is unlikely that the most cost-effective reductions will come from this sector. Instead, they are likely to come from trading with other sectors and through offsets. Increased programmatic goals are likely to cost more and raise rates more than a market-based approach."
Constellation suggests that, "while there is likely more that can be done with energy efficiency and renewables, these mechanisms will have their limitations, as is evidenced by the increased attention to the real costs of wind power with respect to the need for services that can shape the wind power deliveries and ancillary services necessary to provide contingent power supply." SMUD expresses concern that strict command and control goals in areas such as Renewables Portfolio Standard (RPS), energy efficiency, and solar installations would lead to excessive costs and that, "the compliance costs will not be the most cost effective as required by AB 32. Morgan Stanley adds that, "Command and control mechanisms tend to be more complex to administer than market-based approaches and lead to less than optimal investment in GHG reduction technologies."
A second group echoes TURN's sentiment that, "the state would be better served by promoting existing policies that result in real GHG reductions, by developing a comprehensive regional tracking system for greenhouse gases and by deferring the implementation of a cap-and-trade system for the electric sector pending further regional or national developments." LADWP supports "direct regulation through changes in the generation resource mix and avoidance of emissions through energy and water conservation and demand-side management as the least cost approach to reducing emissions for the electricity sector." DRA asserts that "increased programmatic goals likely would increase cost of electricity but not necessarily more so than a cap-and-trade program."
A third group expresses an interest in a dual approach, whereby a cap-and-trade system would be implemented at the same time that the stringency of existing programs such as RPS, energy efficiency, and the Emissions Performance Standard would be increased. SCPPA contends that, "The continuation and expansion of targeted energy efficiency, renewable portfolio, technology development, and similar programs aimed at retail providers as the GHG point of regulation would be compatible with instituting a cap-and-trade." NRDC/UCS assert that, "a cap-and-trade system provides only a generic innovation signal, and targeted policies are more useful for spurring innovation for specific technologies, and overcoming market barriers." NRDC/UCS argue further that both a cap-and-trade system and increased regulatory measures are necessary because, "regulatory policies in the absence of a cap on absolute emissions would not guarantee that the electric sector will meet the GHG reductions goals of the state for this sector."
Parties generally support the incorporation of flexible compliance mechanisms regardless of whether they prefer a cap-and-trade or command and control approach to emissions reductions. Constellation asserts that, "The use of offsets and other flexible compliance tools will help to achieve emission reductions in a cost effective manner and should be incorporated into any emission reduction strategy, whether those strategies are market-based or not."
SMUD asks that retail providers have general flexibility in meeting their targets through existing energy efficiency and renewable programs.
In determining our recommendation for how to regulate the electricity sector in California under AB 32, there are essentially four options that could be adopted individually or in combination: 1) a carbon tax, 2) upstream regulation of emissions from fossil fuel combustion, 3) a downstream emissions cap (with or without trading), and 4) additional direct mandatory/regulatory requirements.
We did not seriously consider the carbon tax option in the course of this proceeding, due to the fact that, if a carbon tax were implemented, it would most likely be imposed on the economy as a whole by the Legislature after recommendations by ARB. Since our focus is on energy sectors only, we did not examine this idea in any detail in this proceeding, nor do we plan to do so.
Similarly, the Market Advisory Committee presented an option for upstream regulation of fossil fuel combustion in California. As the Market Advisory Committee points out, "there is no precedent for using this approach in a cap-and-trade program run by a single agency." However, if this were to be done, ARB may impose it on an economywide basis. While there may be policy reasons for further examination of this approach, which is also under consideration in the United States Congress, we have not undertaken a detailed review of this option for the energy sectors in California. This proposal is not well defined and seems more aimed at a national regulatory regime. Instead, we have focused attention on additional direct mandatory/regulatory requirements and an electricity sector cap or cap-and-trade program.
We begin by examining the direct mandatory/regulatory policies and requirements that California already has in place that contribute to GHG reductions. The State's Energy Action Plan lays out a "loading order" for investment in electricity resources in California that puts energy efficiency as the top priority, with renewable resources second, and clean fossil-fired generation to the extent that other options are not available. To address each of these resource areas, California has three primary policy tools already in place:
· Energy efficiency programs, including building codes and appliance standards,
· The RPS program, and
· The Emissions Performance Standard.
In the case of energy efficiency building codes and appliance standards, the Energy Commission updates these approximately every three years and is continuously including more requirements that reduce electricity use and therefore GHG emissions. These regulations provide a base of electricity and GHG reductions that are permanent and continuous through 2020. We expect these regulations to continue to be enhanced over the entire AB 32 period.
In addition, the Public Utilities Commission sets requirements for the amount of energy savings each investor owned utility (IOU) is required to achieve on an annual and cumulative basis. Current requirements are set through 2013 and are being updated this year in R.06-04-010 to include goals through 2020. The goals are generally set according to the availability of cost-effective energy savings in the utilities' service territories. In D.07-09-043, the Public Utilities Commission also set up a risk/reward mechanism for the IOUs, which allows them to earn financial incentives as they approach meeting their energy savings goals and assesses penalties if they fail to meet at least 65% of their goals.
AB 2021 (Levine, Chapter 734, statutes of 2006) required the Energy Commission, in collaboration with the Public Utilities Commission and the publicly owned utilities (POUs), to set statewide energy efficiency targets for 2017 for all utilities in the state. The legislation requires, among other mandates, that the POUs identify all potentially achievable cost-effective electricity energy savings, establish annual targets for achieving feasible and reliable energy efficiency savings and demand reduction for the next 10-year period, and report these targets to the Energy Commission.
Based upon an assessment of energy efficiency potential available, and considering the need for aggressive energy efficiency savings to help meet climate change goals, the Energy Commission has established a statewide target to achieve 100% of the economic potential identified for energy efficiency. This target is significantly higher than the combined goals proposed by the POUs, the IOUs, or other parties. The Energy Commission expects this statewide target to be achieved through a combination of utility and non-utility programs coordinated at the state level by the Energy Commission and the Public Utilities Commission.
No statutory requirements currently exist for Energy Service Providers (ESPs) or Community Choice Aggregators (CCAs) to invest in energy efficiency for their customers, though their customers fund a portion of the IOU energy efficiency programs through their distribution charges and are currently eligible to participate in IOU-administered energy efficiency programs.
Considering all of this, we recommend that ARB set its scoping plan requirements for energy efficiency at the level of all cost-effective energy efficiency in the State. This requirement would be achieved through a combination of utility and non-utility programs coordinated at the State level, with consistent requirements across all types of retail providers.
The RPS statutes (Senate Bill (SB) 1078 enacted in 2002, as amended by SB 107 in 2006) require IOUs, CCAs, and ESPs to provide a minimum of 20% of delivered energy from renewable sources by 2010. In addition, SB 1078 as amended by SB 107 requires POUs to set RPS targets, but does not specify minimum delivery requirements or the types of renewables that should qualify.
SB 1, enacted in 2006, requires the development of a solar photovoltaic program for California, including both IOUs and the POUs. Production of solar energy at customer sites is another option for reducing GHG emissions from the electricity sector. This program is a direct programmatic measure that will reduce emissions in the sector from customers of several types of retail electricity providers.
SB 1368 enacted in 2006 directed the Public Utilities Commission and the Energy Commission to develop an emissions performance standard for non-renewable, generally fossil-fueled generation resources, for all retail providers of electricity. The Public Utilities Commission adopted regulations for IOUs, ESPs, and CCAs in January 2007 (D.07-01-039), while the Energy Commission adopted regulations for POUs in August 2007; the two sets of requirements are nearly identical. The regulations require all new long-term investments in baseload generation by retail providers to be in power plants that emit no more than 1,100 pounds of carbon dioxide (CO2) per megawatt hour (MWh) produced.
Of the State statutes we have just described, the emissions performance standard statute is the most recent, and it applies its environmental requirements uniformly to all electricity retail providers in California. We agree with the underlying logic of this statutory approach. The goals of AB 32 would be best achieved if all retail providers of electricity, including IOUs, POUs, ESPs, and CCAs, are subject to minimum requirements in the areas of cost-effective energy efficiency and renewables. Such requirements would benefit California customers by ensuring that they receive the GHG emission reductions of cost-effective energy efficiency and renewables. Therefore, we recommend that ARB, as part of its AB 32 regulations, adopt mandatory minimum levels of cost-effective energy efficiency savings required from POUs, at levels recommended by the Energy Commission. Likewise, ARB should adopt mandatory minimum levels of cost-effective energy efficiency consistent with the programs and goals adopted by the Public Utilities Commission for IOUs, CCAs and ESPs.
The POU governing boards have already set 20% renewables goals. Some of the largest POUs plan to achieve that level by 2010, a few have already obtained it, and the rest plan to do so by 2017. We recommend that ARB require that the POUs deliver at least 20% renewable electricity to their customers by no later than 2017 and incorporate this assumption into its scoping plan. ARB should include enforcement mechanisms in its plan, so that it can be assured that the related GHG reductions will be achieved.
In making these recommendations, we have not analyzed whether ARB has the authority to implement these regulations as part of AB 32. Our preliminary analysis suggests that they do. However, if ARB believes that such authority does not exist, we recommend that it seek such authority from the Legislature.
In addition, we also recognize that existing RPS requirements are limited to 20% renewables by 2010. The Public Utilities Commission is prohibited by statute (SB 107 enacted in 200611) from requiring that IOUs obtain more than 20% of their power from renewables. In order to meet the AB 32 goals, the IOUs and POUs should be required to go beyond a 20% level of renewable electricity delivered. Therefore, we recommend that the Energy Commission, Public Utilities Commission, and ARB jointly seek legislation that requires retail electricity providers to obtain a greater proportion of their power from renewables by a date certain, with flexibility to allow the Public Utilities Commission and/or ARB to require exceeding that level under certain conditions (subject to a cost-effectiveness evaluation, for example). The Energy Action Plans jointly adopted by the Public Utilities Commission and the Energy Commission commit us to "evaluate and develop implementation plans for achieving 33 percent renewables by 2020, in light of cost-benefit and risk analysis." While achieving renewable energy deliveries at this level would contribute significantly to attainment of the emissions reductions required by AB 32, we leave open consideration of the appropriate statutory percentage requirements and deadlines, pending further analysis.
We do not adopt the policy, as suggested by some parties, that we should eliminate mandatory targets for energy efficiency and/or renewables, and allow an AB 32 cap to govern instead. As recognized in D.07-12-052, long-term integrated resource planning is now, and will continue to be, an essential component of achieving sustained GHG emissions reductions within the electricity and natural gas sectors. We firmly believe that our existing energy efficiency, renewables, and emissions performance standard policies are the foundation upon which other AB 32 policies should be built. We intend to work with ARB to determine appropriate levels of requirements for each of these types of resources and programs.
With this basis, we turn our attention to the question of whether a cap-and-trade system should be implemented in California for the electricity sector, in addition to the programmatic measures identified above. Before examining in detail the cap-and-trade option, we note that it would be possible to cap emissions from the electricity sector, most likely at the retail provider level, without a provision for trading of allowances among entities in the sector. In D.06-02-032, which was adopted prior to the passage of AB 32, the Public Utilities Commission concluded that GHG emissions should be capped in the electricity sector, but deferred the question of whether emission allowance trading should be implemented. At that time, the Public Utilities Commission contemplated that the GHG cap would apply to the electricity sector only. Now that AB 32 requires an economy-wide cap in California, we see little advantage to a cap system without a trading component, compared to the direct programmatic approaches described above. In addition, a cap without a trading component would offer many fewer advantages than those we describe below for a cap-and-trade program. Therefore, we decline to recommend a cap-only system for the electricity sector in California.
As summarized in Section 3.2.1.1 above, most parties support the inclusion of the electricity sector in a market-based, multi-sector, cap-and-trade program for GHG emission allowances. However, some parties, including TURN, CAISO, CMUA, DRA, PG&E, and SDG&E/SoCalGas, would prefer that California wait to establish a cap-and-trade program until there is either a regional or national system in place.
Our recommendation to ARB is to proceed now to design a multi-sector cap-and-trade system for California that includes the electricity sector. We have a number of reasons for this recommendation. First and foremost, we are cognizant that ARB must develop comprehensive plans by the end of this year for the major sectors of the California economy to meet the 2020 goal. All of the major mechanisms will need to be included in ARB's scoping plan, as required by AB 32, by January 1, 2009. ARB should not simply include a placeholder for cap-and-trade and develop its key provisions later. We believe that the scoping plan should be a blueprint for what California will do if the mechanism is to be in place by 2012, the first year for compliance with AB 32. If ARB determines that market measures are an appropriate means of achieving ARB's and AB 32's goals and ARB further determines that cap-and-trade is the preferred market mechanism, then in order to meet this goal, initial development of a cap-and-trade program should be undertaken now. Detail on how a cap-and-trade program could be implemented in the electricity sector will aid ARB in its assessment of the feasibility and net benefits of a multi-sector program. Our purpose in adopting this recommendation is to provide detail to ARB for its evaluation of a cap-and-trade program design for the electricity sector. We fully recognize that ARB may decide not to adopt a cap-and-trade program for California.
However, we favor inclusion of the electricity sector in a cap-and-trade program for a number of policy reasons. While we fundamentally favor a certain minimum level of mandatory reductions from existing programs as described above, a cap-and-trade system in combination with these mandatory reductions should be able to produce the GHG emissions reductions required by AB 32 at a lower cost than sole reliance on additional mandatory reductions. This is because emission allowance trading would maximize flexibility in achieving emissions targets by allowing obligated entities to rely on the least-cost abatement options throughout the economy. This, in turn, would provide strong incentives for investment in research and innovation in technologies that lower GHG emissions. A trading system also would allow market participants to manage risk associated with compliance obligations. Finally, it would internalize GHG externalities and should distribute the cost of GHG reductions efficiently across all capped entities. This is valuable because the impacts of GHG emissions are felt by all Californians.
We agree with several parties, including NRDC/UCS, that the cap-and-trade system need only produce a relatively small portion of the overall emissions reductions in the short term. We recommend that ARB design it as a complement to existing policies and their expansions as noted above. As described above, a large portion of the emissions reductions in the electricity sector will come from mandated investments in energy efficiency and other demand reduction programs, as well as renewable energy goals. The additional reductions due to a cap-and-trade system from the electricity sector will likely be small beginning in 2012, but may expand as experience with the mechanism and compliance obligations increase over the AB 32 time period. Furthermore, one of the advantages of a cap-and-trade system is that it facilitates cost-effective GHG reductions from other sectors within the multi-sector cap. This opportunity to gain experience with the cap-and-trade mechanism, in addition to finding real least-cost reductions, is a major reason for our recommendation to proceed now with cap-and-trade for the electricity sector.
In addition, AB 32 requires that ARB design any cap-and-trade program to ensure that there be no increase in the emissions of toxic air contaminants or criteria air pollutants and that localized impacts in communities already adversely impacted by air pollution be minimized. Our recommendation is consistent with other federal, State, and local environmental requirements pertaining to criteria pollutants, and we are confident that these tests can be met.
Finally, we are confident that California can design its cap-and-trade program in collaboration with the other states in the Western Climate Initiative. The timeframe set for the Western Climate Initiative to agree on a design framework and principles is similar to ARB's AB 32 timeframe. Therefore, we intend to continue to work with the other states to develop a coordinated approach. While the approach recommended by the Western Climate Initiative might not be identical to the system we propose for California, we believe that there will be adequate time prior to 2012 to ensure consistency among the cap-and-trade designs.
3.3. Point of GHG Regulation in a Cap-and-Trade System
In this section, we consider the point of regulation or entity in the electricity sector with responsibility for compliance in a multi-sector cap-and-trade system in California. There are four primary options under consideration for point of regulation in the electricity sector:
Retail Providers. In what has been called a "load-based" or "retail provider-based" approach, the regulated entities would be the retail providers of electricity to California customers. Retail providers would be required to obtain and surrender emission allowances for the GHG emissions associated with all power (including both in-state generation and imported electricity) sold to end users in California. Generators would not have a compliance obligation under this approach, except possibly for exported power. We agree with CMUA that "retail provider" is a more accurate and descriptive terminology, and use that term herein.
In-State Generators. In what has been called a "pure source-based" approach, the regulated entities would be generators (owners or operators of power plants) located in California. Emissions attributed to all in-state generation, whether used to serve California load or exported, would be included in a cap-and-trade system. Under such a system, electricity use associated with imports would not be directly regulated under the cap-and-trade system, but could be included in determining whether California economy-wide emission reduction goals are reached consistent with AB 32.
Deliverer. The structure of what has been called the "first seller" approach was a matter of some discussion in this proceeding. The Market Advisory Committee suggested that the point of regulation should be the "first seller" of power into California electricity markets.12 As explained in Section 3.3.2.6, we recommend a variation of the first seller approach, in which the point of regulation would be specified as the entity that owns the electricity as it is delivered to the grid in California. We use the term "deliverer" to describe this regulatory approach.
In-State Generators/Retail Providers for Imports. A fourth point of regulation approach that has received consideration is a hybrid system in which the point of regulation would be the generators (owner or operators of power plants) for in-state generation with the retail providers responsible for imported electricity.
In this section, we summarize the positions of the parties on the appropriate point of regulation in the electricity sector for a cap-and-trade program in California.
The retail provider (or load-based) point of regulation imposes the obligation on retail providers to retire allowances corresponding to the emissions associated with the electricity generated or procured to serve customer loads. Parties' positions are divided about the desirability of this approach to regulating GHGs. Generally, the retail provider approach is supported by POUs and opposed by IOUs, ESPs, marketers, and generators.
LADWP believes that the retail provider-based approach "remains the superior and only feasible approach," if applied to a California-only GHG emission reduction program. According to LADWP, its advantages include consistency with energy efficiency and renewable initiatives, minimized costs of retail providers instead of relying on high market prices to change generation dispatch, and that it is least susceptible to legal challenge.
SCPPA states that "the number of regulated entities would be minimized in contrast to either the first seller or the hybrid approach, leading to administrative simplicity."
SMUD also supports the retail provider approach, expressing its view that, "Assumptions about the carbon content of market purchases would have to be made but these assumptions would be required under the first seller concept as well. The retail service provider would be in the best position to balance the level of energy efficiency, renewable energy or other low carbon strategies needed to meet its GHG goals."
While TURN's overall recommendation is to delay implementation of a cap-and-trade program, TURN recommends further analysis of the feasibility and relative benefits of a retail provider-based regulatory system using tradable emission attribute certificates (TEACs), an option described in more detail below.
PG&E and SCE are strongly opposed to a retail provider-based approach for a number of reasons, most of which stem from their concerns regarding inaccuracies that may arise in reporting and tracking emissions and may result in gaming opportunities and market distortions. Furthermore, PG&E argues that, "because a national system is likely to be source-based, California would have to invest a large amount of money and effort to create a system that would quickly become obsolete..."
The CAISO Market Surveillance Committee asserts that a retail provider-based system is inferior to the other options. It states that load-based and source-based systems are essentially the same on the issues of determining the GHG content of power imports and incentives for investments in energy efficiency and renewable energy. However, it contends that a retail provider-based system has serious disadvantages in other respects: administrative complexity, adverse impacts on the efficiency and costs of dispatching generation units, and incompatibility with likely federal GHG legislation.
The CAISO Market Surveillance Committee contends that a retail provider-based system in which retail providers signed contracts with individual generators to minimize the cost of serving load results in the same cost to load as a source-based system in which generators maximize profit and emission allowances are allocated to retail providers for subsequent auction to generators.13 It asserts, however, that due to the effects of a retail provider-based system on wholesale markets, particularly the CAISO markets, it would lead to the deployment of a less-efficient generation mix, thereby resulting in higher, not lower, energy costs for consumers. The CAISO Market Surveillance Committee concludes that the resulting cost of energy to consumers would likely be higher under a load-based cap.
Although NRDC/UCS would support any of three point of regulation options (retail provider, deliverer, or hybrid), they state that each has different strengths. NRDC/UCS support LADWP's and SCPPA's comments that a retail provider-based cap will produce stronger incentives for retail providers to invest in low-GHG emitting technologies.
11 Public Utilities Code Section 399.15(b)(1) states that "A retail seller with 20 percent of retail sales procured from eligible renewable energy resources in any year shall not be required to increase its procurement of renewable energy resources in the following year."
12 Market Advisory Committee report, at 42.
13 The CAISO Market Surveillance Committee describes two sources of rents that, in its view, producers can capture with the implementation of a GHG cap-and-trade system: "allowance rents" and "rents of clean generation." "[I]f allowances are given to load, and then sold to generators (perhaps via an auction) for use in a source-based system, with the proceeds returned to consumers, then these rents will, to some extent, offset the price increases resulting from the cap-and-trade mechanism. These rents are also retained by consumers under a load-based system."
It states that generation units with low emissions would also benefit from higher energy prices because price increases will exceed their allowance expenses, that these "rents to clean generation" would be retained by independently owned generators, and, for generation owned by utilities, any such additional profits could be returned to consumers. It concludes that consumers could, under either a retail provider or first seller point of regulation, retain the allowance rents as well as the portion of rents to clean generation that accrue to utility owned and new renewable generation.
