V. Attributing GHG Emissions to Various Sources of Electricity
For purposes of reporting GHG emissions, the Joint Staff explains that the sources of power used to meet retail load fall into two categories: power that can be tracked to a specific facility (specified sources) and power that can only be tracked to a mix of power plants at one of various geographic levels (unspecified sources).
In order to assign responsibility for GHG emissions to retail providers, the appropriate emissions factor of each source of power must be determined. This emission factor multiplied by the amount of power generated to deliver the power received from the source will yield the gross amount of emissions to be attributed to the retail provider, which must be adjusted for wholesale sales to other entities. For specified sources, the plant-specific emission factor will be established by ARB based either on its own source-based reporting requirements or on data filed with the United States Environmental Protection Agency (EPA) or the Energy Information Agency (EIA). Suppliers that own their own fleet of generation resources may also obtain supplier-specific emission factors from ARB. For unspecified sources, estimated default emissions factors must be established.
A. AB 32 Requires Accurate Reporting and Real Emissions Reductions that Are Enforceable by ARB
AB 32 requires ARB to adopt, on or before January 1, 2008, regulations to govern the reporting and verification of statewide greenhouse gas emissions and to monitor and enforce compliance with this program. (Section 38530(a).) The reporting system adopted by ARB will be used to ensure that the identified GHG reductions are "real, permanent, quantifiable, verifiable, and enforceable" by ARB. (Section 38562(d)(1).) The reporting and verification system is central to determining individual entities' compliance with AB 32 and ensuring that the overall goals of AB 32 are achieved.
Retail providers balance a variety of objectives when procuring electricity. In addition to accommodating the variability of electricity demand that occurs from hour to hour, retail providers must factor in price volatility of underlying fuel sources, reliability of power sources, various Public Utilities Commission and Energy Commission program requirements (including Renewable Portfolio Standard (RPS), energy efficiency, and resource adequacy requirements), and general market volatility. As a result, retail providers use a variety of complex commercial arrangements to procure power.
As Staff notes, these complex arrangements may make it difficult to determine the true effect that a procurement choice can have on a retail provider's GHG emissions. With the exception of source-specific contracts, electricity can be resold and repackaged multiple times before a retail provider purchases it. Even with a source-specific contract, other power may be substituted should the need arise. Such transactions make it difficult to track the electricity to its original source. Therefore, default emission factors must be established based on analysis of sources in a region.
Staff is concerned that, with the advent of GHG regulation to meet AB 32 requirements, a retail provider may modify its power contracts or purchases from CAISO markets and report its power acquisitions in a manner that would make it appear that the retail provider has reduced its GHG emissions when, in reality, the same amount of GHG emissions is occurring as before.2 In its report, Staff provides an example, as follows. A California retail provider that has an ownership share in an out-of-state high GHG-emitting generating facility could sell that power to an out-of-state entity which, in return, sells to the California retail provider the same amount of power but obstensibly from a lower GHG-emitting source. If the retail provider's emissions are calculated based only on the purchase from the out-of-state entity, it could appear that the California retail provider has reduced GHG emissions. However, in reality, the same amount of GHG would be emitted into the atmosphere.
Staff reports that there is sufficient relatively low-GHG generation (including from natural gas-fired plants) available outside of California such that, if such contractual power swap arrangements were treated as reducing the California retail provider's GHG emissions, California retail providers could be deemed to largely meet the statutory GHG reduction targets but with no reductions in the total GHG emissions due to electricity generation in the WECC region.
The Joint Staff recommends that conditions be imposed on the recognition of facility-specific purchases for GHG accounting purposes to ensure that the power purchase truly modifies generation from the specified plant. The Joint Staff explains that one acceptable condition may be the existence of a long-standing contractual relationship between the retail provider and a specified plant. At the same time, the Joint Staff cautions that new contracts for existing low- or zero-GHG plants are unlikely to yield real reductions in GHG emissions, commenting that "there is little reason to believe that an agreement between a retail provider and an existing plant will induce generation that would not have occurred anyway." Staff states that any new plants owned or partially-owned by a retail provider should be viewed as being used to meet the retail provider's load. The new power plants would reduce overall demand for existing generation sources and, if the new power plant has lower GHG emissions than the previous source the retail provider utilized, a real reduction in GHG emissions would result. The Joint Staff also suggests that a long-term power contract signed between a retail provider and a developer prior to a plant's construction would be sufficient to demonstrate a causal link between the retail provider and the addition of the specified new capacity.
Several parties object to the Joint Staff's proposal to restrict the manner in which emission factors would be attributed to power that retail providers report as being received or sold from specified sources.
Several parties contend that the Joint Staff's proposed conditions regarding the treatment of emissions for power received or sold from specified resources are not consistent with AB 32. In these parties' opinion, the intent of AB 32 was to reduce the carbon footprint of electricity consumed in California. They recognize that the intent of AB 32 is to mandate reductions in GHG emissions, but they argue that AB 32 does not support the Joint Staff's attempt to limit contract shuffling. In these parties' opinions, AB 32 does not purport to regulate GHG emissions from generation outside California if the electricity is not consumed in California. These parties argue that AB 32 prevents ARB from regulating out-of-state GHG emissions not caused by electricity consumed in California. Parties also argue that it would be impermissible to regulate a California retail provider that sells a higher-emission resource and replaces it with an existing lower-emission resource. They assert that, as a state law, AB 32 cannot and should not affect the carbon reduction strategies of other states.
Several parties interpret the Joint Staff proposal as an attempt to disapprove or prohibit certain contracts. They interpret the Staff reference to limiting "claims" to existing low- and zero-GHG resources as a proposal to restrict their ability to enter into contracts with existing resources.
Parties argue that limiting facility-specific contracts would be contrary to criteria proposed by the Joint Staff. In particular, they assert that the Joint Staff's limits would have the unintended consequence of preventing California utilities from seeking and procuring existing renewable resources outside California.
CMUA and Morgan Stanley Capital Group Inc. (Morgan Stanley) argue that contract shuffling is not a large concern because of Senate Bill (SB) 1368 and other states' RPS goals. These parties contend that SB 1368 places significant restrictions on the procurement of unspecified resources to meet a retail provider's load.
There are several potential types of contractual arrangements that could be used to show "paper" emission reductions, but which would not actually reduce GHG emissions. A California retail provider could sell power from its owned (or partially-owned) high-GHG generation facility to an out-of-state entity and simultaneously purchase power from a lower-GHG specified source, or from an unspecified source with a lower default emission factor. If left unchecked, incentives for this type of contract shuffling would be strongest for out-of-state high-GHG plants in either a load-based or first-seller GHG regulatory structure, and also for in-state high-GHG plants in a load-based GHG regulatory structure if the retail provider is not responsible for emissions associated with exports. If the nature of such a contract shuffle is not recognized, the retail provider's reported GHG emissions would decline but, in reality, the high-GHG power plant would still be operating, making it unlikely that the total amount of GHG emissions within the region had actually been reduced. A source-based GHG regulatory system throughout the WECC region would greatly limit, if not eliminate, the incentives to engage in this type of contract shuffling.
In a similar strategy that could show illusory emission reductions, a California retail provider that usually purchases power from a relatively high-GHG source (specified or unspecified) could buy power instead from another existing source with a lower GHG emission factor, thus appearing to reduce its GHG emissions. If the relatively high-GHG source continues to operate, total GHG emissions may remain at previous levels, with no real reduction in GHG emissions. As in the previous example, such opportunities, if unchecked, would provide the strongest incentives for contract shuffling if the relatively high-GHG source is out-of-state. This is because GHG emissions from this source no longer would have to be reported to ARB, leading to an apparent reduction of California electricity sector emissions.
We agree with Staff that, through selling or otherwise not taking receipt of power from their high-GHG facilities or power purchase contracts and replacing that power with existing low-GHG resources that would have operated anyway, California retail providers could attempt to receive credit for GHG reductions that are not real, as illusrated by the above examples. We believe that such attempts to transfer responsibility for existing emissions would be counter to the intent of AB 32. If other states in the WECC region were to adopt GHG regulations, such attempts might be less problematic since the relatively higher-emitting sources would become subject to another state's GHG regulations. However, since there is no regional or federal GHG regulatory system in place at this time, ARB should send a strong signal now to discourage contract shuffling, by not permitting the apparent emissions reductions to be counted under the reporting and verification protocol. Broader policy questions concerning contract shuffling and other measures that might be taken to minimize and mitigate various forms of this practice should be addressed more completely in the context of the overall compliance framework. By employing an interim deterrent, we seek to avoid a situation in which retail providers could accumulate significant apparent emissions reductions that are highly unlikely to be recognized in the eventual compliance regime.
In their comments, several parties argue that AB 32 does not provide any authority to deal with the problems that the Joint Staff identify as contract shuffling. One of the arguments made is that contract shuffling is not necessarily "leakage" as defined in the statute. (Section 38505(i).) However, while minimizing leakage is one of the goals of the statute (Section 38562(b)(8)), the statute also requires ARB to ensure that the "greenhouse gas emission reductions achieved are real, permanent, quantifiable, verifiable, and enforceable" by ARB. (Section 38562(d)(1).) We propose that ARB adopt verification conditions that would prevent the attribution to retail providers of GHG emission reductions that are not real. Accordingly, such regulations are within the scope of the statutory authority.
Several parties object to the Joint Staff report's concept of rejecting "claims" to specified sources. We think that the language concerning "claims" used in the Joint Staff report caused unnecessary confusion and accordingly we do not use this terminology in the proposed rules. The question we are dealing with here is whether a shift in the reported source of power would result in real emission reductions. If not, the retail provider should not get credit for illusory emission reductions.
While the Southern California Public Power Authority (SCPPA) raises such a concern in its comments, the regulations we recommend to ARB would not cause any quantity of electricity to go unreported. Nor would they regulate out-of-state facilities selling electricity for consumption outside of California, as claimed by CMUA. Rather, these regulations would specify the level of emissions that ARB would attribute to power obtained by a California retail provider in a manner that would ensure that any identified GHG reductions are real, as required by AB 32. These regulations are not intended to affect the carbon reduction strategies of other states, only to ensure that California's carbon reduction strategies produce real reductions in carbon emissions.
The recommended reporting regulations would not prohibit parties from entering into contracts for the supply of electricity that they are otherwise permitted to enter into, a concern raised by the Los Angeles Department of Water and Power (LADWP). What these regulations would establish is the level of GHG emissions that would be attributed to electricity procured pursuant to reported contractual relationships. To avoid the mistaken identification of GHG reductions that are not real, in some instances these regulations would require that the level of emissions attributed to certain power for the purpose of GHG accounting be different than the level of GHG emissions that occurs from the source specified in the contract.
Some parties object to a suggestion in the Joint Staff report that certain contract shuffling problems might be dealt with by treating some purchases from specified in-state generating resources differently than purchases from specified out-of-state resources. We agree with these commenters that that suggestion should not be pursued further.
The methods that we recommend to ARB for attributing GHG emissions related to the purchase of power from existing specified sources and the sale of power generated by owned power plants would allow more accurate tracking of GHG emissions and avoid the calculation and attribution of GHG reductions that are not real. These recommendations are also discussed in Sections V.B.2 and V.D.1 of this order, and the recommended reporting and verification protocol is set forth in Attachment A.
In verifying GHG emissions associated with owned or partially-owned power plants, we recommend that ARB consider first the GHG emissions related to the full ownership share of the output of the plant. Under a load-based GHG regulation approach, once emissions associated with the retail provider's ownership share of the plant's generation are known, ARB would subtract emissions attributed to power sales from the plant3. Emissions attributed to sold power that is delivered to a point of delivery in California for use to serve California load would be subtracted, based on the emissions profile of the power plant, since under AB 32 those emissions are the responsibility of the retail provider using the power to serve its load (as discussed further in Section V.D of this order).
For other sales, the attributed emission factor may depend on the reason for the sale, to prevent the reporting of emission reductions that are not real. ARB would attribute emissions to the sale based on the emissions profile of the power plant under the following circumstances, because they would not raise contract shuffling concerns:
· If the power could not be delivered to the retail provider or the retail provider had surplus power during the hours in which it was sold, or,
· If the power was from a California-eligible renewable plant with WREGIS certificates transferred to the buyer along with the power.
For sales under other circumstances, we recommend that ARB attribute emissions to the sale using an average emission factor of the retail provider's sources that were available for unspecified sales (described in Section V.D.2 of this order). This recommendation would apply only to the portion of the sale that exceeds ten percent of the retail provider's proportional ownership share of the generation, in recognition of the fact that the retail provider may need some flexibility in receiving power from the power plant in order to meet its operational needs.
For GHG accounting purposes, we view contractual arrangements in which the purchasing party has a contractual entitlement to a specified percentage of the output of a power plant as comparable to an ownership interest in the power plant. The incentives for selling the power from such plants, if they have relatively high GHG emissions, would be the same as for partially-owned plants. Thus, for GHG reporting purposes, retail providers should report power they receive or sell from such plants as being from partially-owned plants, and ARB should attribute emissions to the purchases and sales from those plants on that basis.
As an additional step to ensure that reported emission reductions are real, the proposed decision recommended that ARB attribute emissions associated with any purchases through new contracts with existing specified sources based on the default emission factor of the region in which the specified source is located. However, based in large part on comments on the proposed decision, we conclude that the largest concern about contract shuffling associated with new contracts with existing sources arises with new contractual arrangements with existing nuclear or large hydro plants.4
Due to the nature of nuclear and large hydro plants, they almost always are operated at the full capacity of which they are capable. Therefore, if a retail provider buys additional power from such a plant to replace power previously obtained from another source (e.g., from a high-GHG source), it is logical to conclude that the nuclear or large hydro facility is not producing more power to fulfill the new contract. Rather, it is most reasonable to conclude that the entity that previously obtained that power from the nuclear or hydro facility will have to obtain replacement power. Therefore, the real reduction in GHG emissions is not the difference between the emissions rate of (i) the old (high-GHG) source and (ii) the nuclear or hydro source. Rather, the real reduction in GHG emissions is the difference between the emissions rate of (i) the old (high-GHG) source and (ii) the emissions rate of the replacement power procured by the party that previously received power from the nuclear or hydro source. To best reflect that difference, the recommended protocol ascribes to the power purchased from the existing nuclear or large hydro power plant the default emission factor for the region in which the plant is located.5
We are less convinced that operations of other types of existing power plants could not be improved, in terms of reducing GHG emissions on a regional basis, through contractual modifications. For example, shifting generation from less-efficient to more-efficient natural gas-fired power plants may become more advantageous with the recognition of the value of GHG emission reductions. Additionally, limiting the attribution of default emission factors to new contracts with existing nuclear and large hydro plants would encourage greater contracting flexibility for ESPs and other market participants that may rely more heavily on short-term contracts. Further, emission factors of existing natural gas facilities are closer to the regional default emission factors, so use of regional default emission factors would have relatively small impacts on attributed emissions. For these reasons, we reject the recommendation in the proposed decision that would attribute regional default emission factors to all purchases through new contracts with existing specified sources.
We make these recommendations because it is our opinion that the high demand on all resources in the WECC region makes it unlikely that replacing power from relatively high GHG-emitting resources with power from existing lower GHG-emitting resources would result in operational changes for the resources or in lower total GHG emissions in the WECC region. The emission attribution procedures we recommend help ensure that GHG reductions that ARB may calculate as result of a retail provider replacing generation from a high GHG-emission source with lower GHG-emission purchases are based on a convincing showing that real GHG emission reductions were achieved.
PG&E and other parties argue that AB 32 does not allow the attribution of emissions other than those actually occurring at a contracted resource, citing Section 38530(a), which requires ARB to adopt regulations for the "reporting and verification" of GHG emissions from GHG sources. This argument ignores a key portion of Section 38530(a), which provides that the reporting and verification regulations to be adopted by ARB are to "monitor and enforce compliance with [California's] program" to reduce GHG emissions. A key element of this program is that the GHG "emission reductions achieved are real..." (Section 38562(d)(1).) As described above, a reporting and verification regime that allowed a retail provider to reduce the emissions attributed to it through contractual changes without there being actual reductions would violate this requirement. The methods that we propose to attribute emissions in certain instances according to historical contractual arrangements rather than the sleight of hand that Staff calls contract shuffling would ensure that the reporting entity does not receive improper credit for emission reductions that are not real, consistent with Section 38562(d)(1). Accordingly, we reject this argument.
SDG&E and CMUA argue that the definition of "statewide greenhouse gas emissions" in Section 38505(m) precludes ARB from enacting regulations that would attribute to power delivered to California a GHG emissions rate different than the emissions rate of the generation facility specified in the contract under which the power is delivered. However, Section 38505(m) does not refer to the emissions of specific generation facilities or how to calculate the emissions from specific facilities. Instead, it generally refers to the "emissions of greenhouse gases from the generation of electricity delivered to and consumed in California . . . whether the electricity is generated in state or imported." The apparent purpose of the cited language is to ensure that imported electricity is not omitted in calculating the overall GHG emissions for which California is responsible. The regulations we propose would achieve this purpose, while also ensuring that reported emission reductions are real. Accordingly, we decline to conclude that the general language contained in Section 38505(m) overrules the requirement of Section 38562(d)(1) that emission reductions be "real."
Sempra Global (Sempra) objects that there is nothing in the record to support the conclusion in the proposed decision that "it is unlikely that new contracts with existing generation sources would produce real reductions in GHG emissions, since most, if not all, of existing power plants would run the same regardless of any new contract." With the revisions we make to the recommended Protocol, the use of default, rather than plant-specific, emission factors would be limited to purchases under new contracts with existing nuclear and large hydro plants. As explained above, these plants usually are operated at full capacity to the extent possible, so that changes in contractual arrangements for their output would not change GHG emissions. If an entity believes that use of default emission rates does not recognize a real reduction in GHG emissions, it can make its case to ARB, as provided in Section 2.14 of the Protocol in Attachment A, that a different emissions factor should be used so as to reflect the actual reduction in GHG emissions.
Sempra argues further that, "Because the proposed rule [in the proposed decision that would assign default emission factors to purchases from certain existing generation facilities] would have the effect of directing that wholesale sellers of electricity from existing units could only contract with their current counterparties, the rule could easily be found to unlawfully interfere with interstate commerce. Also, limiting the seller's pool of potential buyers to a single party could be viewed as creating an unlawful restraint on trade." However, the regulation we are proposing today, as compared to the rule proposed in the proposed decision, would apply default emission factors to a much smaller group of existing generation facilities. Furthermore, nothing in the regulation would require wholesaler sellers of electricity from existing power plants to contract with their current counterparties.
One impact of establishing a GHG cap that applies only to California is that a low-GHG emitting power plant may be a more valuable source of electricity to a California retail provider than it is to a retail provider from a state that has no GHG cap. Thus, under the proposed regulations, there may be a financial advantage for the seller of electricity from an existing power plant to sell to certain California retail providers, rather than to a retail provider from another state. However, this advantage would apply equally to sellers of power from existing low-GHG plants whether they are located inside California or out of state. Thus, there is no discrimination against interstate commerce. These regulations, of course, may have an incidental impact on interstate commerce, just as different minimum wages in different states may have an incidental impact on interstate commerce; but it is not unlawful for a state to establish regulations that have an effect on interstate commerce.6
As for Sempra's argument concerning restraint of trade, also made by Independent Energy Producers Association (IEP), these parties provided no citation to any particular anti-trust law that the proposed ARB regulations might violate. Indeed, we are not aware of any situation where a state law or regulation that requires private parties to behave in a certain way has been held to violate the anti-trust laws. Here, the proposed regulations would require the covered entities to comply with the ARB's reporting requirements.
IEP argues that there may be a taking if the GHG regulations strip away the economic value of the environmental attributes (i.e., low GHG emissions) associated with a particular power plant, by using a default emission factor in calculating emissions. This argument ignores the fact that the economic value to which IEP refers (the value of a power plant with low GHG emissions under a GHG regulatory scheme) is created by that regulatory scheme. Therefore, creating this regulatory scheme does not deprive the owner of anything that was already owned.
CMUA argues that the recommended reporting protocols may result in a regulatory taking requiring the payment of compensation. It discusses the situation of a California retail provider that owns a share in a high-emitting GHG power plant. CMUA contends that, in order to reduce its GHG emissions, that retail provider would have to sell its share in the power plant, or lay-off the owner's proportional share of the power. CMUA apparently argues that these would be the retail provider's only options because it could not get credit for reducing GHG emissions by buying power from an existing low-GHG power plant. Due to revisions that we make in the protocol recommended in the proposed decision, purchases from many existing lower-GHG power plants would allow the retail provider to show lower GHG emissions. But even if this change were not made in the protocol, the retail provider would still have the option of buying low-GHG power from a new power plant, or using allowances to offset its emissions. Only the reporting protocol is now at issue. Regulations that ARB will regarding, for example, the distribution of allowances (e.g., whether auctioned or allocated for free, and if so how) and the rate at which any particular retail provider will be required to reduce its GHG emissions, have not yet been determined. Therefore, it is premature to argue that these reporting protocols would have the particular economic impact predicted by CMUA. Furthermore, even if a retail provider were to be required to sell its share in a power plant to achieve AB 32 compliance, the owner would not be deprived of all economic use of its property, as CMUA contends, if someone would be willing to buy that share in the power plant. CMUA does not explain why the owner could not sell its share to an entity not subject to California's GHG controls. Nor does CMUA cite any cases holding that there is a regulatory taking if a pollution control requirement causes an owner of a plant to shut it down entirely.
CMUA also argues that there would be a regulatory taking if a power plant owner has to sell its ownership share or lay off its share of the power, because that would "interfere with the owner's reasonable investment-backed expectations whereby the owner could not have contemplated that contingency years ago during the initial investment." As explained above, these are not the only possible ways of that the owner could deal with the high-GHG emissions of a coal plant. Moreover, we are not aware of, and CMUA does not cite, any case where a requirement that an owner of power plant reduce pollution has been held to be a regulatory taking because that requirement has reduced the value of the power plant and the owner had no expectation that it would have to meet those particular pollution requirements when it invested in the power plant.
CMUA and NCPA seek clarification as to how the Protocol would treat emissions associated with power that is generated by a retail provider outside of California and also delivered and consumed outside of California. They take the position that emissions associated with such power should always be excluded from the retail provider's emissions profile for California. We agree that the amount of such power should be subtracted from the total amount of power generated and purchased by that provider. However, to prevent the counting of emission reductions that are not real, in a contract shuffling situation the Protocol would attribute to certain sales an emissions factor different than the emissions factor of the plant specified in the sales contract. In short, ignoring the retail provider's ownership share, and its corresponding share of sales from the plant, would defeat the regulations designed to prevent retail providers from showing GHG emission reductions that are not real.
B. Specified Sources
A clear link between power delivered to a retail provider and a specific generating facility may exist if a retail provider owns or has an equity share in the facility or if it has a contract to purchase power from the facility. In some cases, certain utilities also receive specific allocations of power from federally-managed hydroelectric facilities. The GHG emissions associated with the delivered power can be determined with reasonable certainty based on these specified sources.
The Joint Staff describes that some contracts for purchasing power may describe a group of substantially identical resources at a single location as the source of power. We agree that, in that situation, it would be appropriate to treat the group of resources as a specified source for purposes of GHG accounting.
We address the determination of emission factors for power received from different types of specified sources in turn.
4. Emission Factors for Owned or Partially-owned Specified Sources
In the Joint Staff report, Staff proposes that, for each wholly- or partially-owned generation source, the GHG emissions be based upon ARB-approved source data and, in the case of partially-owned generation, emissions should be allocated on the basis of the amount of electricity taken. Staff proposes, however, that reporting entities be required to provide explanations whenever the share of generation taken deviates from the ownership share, with the apparent view that adjustments may be warranted if it appears that the retail provider engaged in a form of contract shuffling in an attempt to reduce its GHG emissions responsibility.
LADWP seeks clarification on the appropriate emission factor for coal-based generation sources. As described above, ARB plans to establish emission factors for each wholly- or partially-owned generation source. We encourage LADWP to address its concerns through the appropriate ARB workgroup.
SCPPA objects to the use of ownership shares in calculating the GHG emissions to be attributed to a retail provider that owns a portion of a particular generating facility, stating that the attribution of emissions should be on the basis of actual deliveries. For reasons described in Section V.A., we recommend that ARB initially attribute emissions for owned and partially-owned power plants proportional to an entity's ownership share, adjusted for sales of power from the plant. As detailed in Sections V.A and V.D, emissions would be attributed to the sale of power from the power plant, either by the retail provider or by the plant operator on behalf of the retail provider, based on the emission factor of the power plant for sales to another retail provider in California; if the power could not be delivered to or was not needed by the owner; and for sales from renewable resources. In those situations, the emissions associated with the generating facility would no longer be the responsibility of the reporting retail provider. Thus, the proposed regulations we recommend to ARB, taken as a whole, would not automatically result in a retail provider being responsible for all of the GHG emissions associated with its ownership share of a plant. However, the requirement that retail providers provide an explanation does permit ARB to act in particular instances to prevent the reporting of reductions in GHG emissions that are not real.7
No party raised concerns with Staff's recommendation that ARB establish GHG emission factors for owned and partially-owned generation. It is our understanding that ARB will determine the emission factors for owned and partially-owned generation based on either its source-based reporting protocol or data that generators are required to file with EPA or EIA. As explained above, if a retail provider has a contractual entitlement to a specified percentage of the output of a power plant, that source would be treated as a partially-owned plant for purposes of GHG accounting.
For most power purchased from specified sources or obtained through exchange agreements from specified sources,8 ARB will develop emission factors using information provided by in-state sources under ARB's source-based reporting requirements or, for out-of-state sources, from voluntary reporting by those facilities or from EIA and EPA data. We address the appropriate emission factors for attribution to purchases from various types of specified sources.
We recommend that ARB attribute emissions for purchases from specified sources based on emission factors of the specified source, except for new contracts with existing nuclear and large hydro power plants entered into on or after January 1, 2008. As described in Section V.A, in our opinion it is unlikely that such new contracts would produce real reductions in GHG emissions, since existing nuclear and large hydro power plants would be expected to run the same regardless of any new contract. Therefore we recommend that ARB attribute emissions to purchases made pursuant to new contracts with existing nuclear or large hydro plants based on the default emission factor for the region in which the plant is located.
The term "null power" refers to electricity generated from a renewable resource for which the renewable and environmental attributes have been sold to another party. In D.07-01-039, the Public Utilities Commission decided that, for the limited purposes of the emissions performance standard, null power would be assigned the emissions value of the underlying renewable generation.9
Southern California Edison Company suggests that this approach be followed in our reporting recommendations to ARB. Center for Resource Solutions (CRS) proposes that null power be assigned system average emission characteristics. Sacramento Municipal Utility District (SMUD) proposes similarly that null power be assigned a default emission factor for the region in which the null power is generated.
Because California has not adopted Renewable Energy Credits (RECs), it would be premature to choose among these approaches at this time. The Public Utilities Commission is currently reviewing in R.06-02-012 the possible relationship between the renewable and environmental attributes embodied in a REC and the associated power. The attribution of GHG emissions to null power is an issue that will be dealt with as California decides whether to implement a REC program.
Some contracts for the purchase of intermittent renewable resources such as wind and solar contain provisions that provide for the use of non-renewable resources to "firm" the power to meet the energy profile needs of retail providers. SMUD recommends that the non-renewable power used to firm intermittent renewable resources be assigned the carbon attribute of the associated renewable resource. SMUD states that this treatment would be consistent with how both Commissions have implemented the emission performance standard.
In D.07-01-039, we differentiated between two types of contracts with intermittent renewable resources that include firming energy: (1) contracts in which the firming resource is specified, and (2) contracts in which the firming resource is unspecified.10 If the firming resource is specified, we determined that each individual resource must be compliant with the emissions performance standard adopted in D.07-01-039. In cases where the firming resource is unspecified, we limited the amount of substitute energy purchases from unspecified sources such that, "For specified contracts with intermittent renewable resources (defined as solar, wind and run-of-river hydroelectricity), the amount of substitute energy purchases from unspecified resources is limited such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) do not exceed the total expected output of the specified renewable powerplant over the term of the contract."11
For the purposes of GHG reporting we recommend a similar approach, although our focus here is on annual GHG accounting rather than the generation and receipt of power over the life of the contract. If a contract with an intermittent renewable resource provides that firming energy will be provided, and if the total purchase under the contract is no more than the energy generated from the renewable facility in the reporting period, the firming energy should be attributed the same emission characteristics as the contracted renewable power plant and need not be reported separately. Any firming energy used beyond the amount of renewable power attributed to the reporting entity in WREGIS shall be reported consistently with the source of the firming power, i.e., generated from owned assets or purchased from specified or unspecified resources.
D.07-01-039 only dealt with long-term contracts and did not address how to treat circumstances where the retail electricity provider takes energy from a renewable resource and provides its own firming (in contrast to contracts in which the renewable energy seller does the firming). In these cases, emissions attributed to the renewable energy should be based on the characteristics of the renewable resource, and the firming energy should be attributed emissions based on its source, whether specified or unspecified.
Contracts for power from a specified source may be structured such that the seller will fill in power from the specified plant with power from unspecified sources during planned and unplanned outages, start-ups, ramp rates, and other operating conditions that limit the plant's output. SMUD requests that substitute power provided under such contracts be attributed the emission factor of the contracted-for facility.
In D.07-01-039, we permitted contracts that would otherwise meet the emissions performance standard to provide for substitute energy purchases up to 15 % of the forecasted energy production of the specified power plant over the term of the contract, provided that the contract only permits the seller to purchase system energy for substitute energy.12 However, the emissions performance standard does not have the same purpose as the GHG reporting protocols. The emissions performance standard is a gateway standard that determines the types of long-term contracts that load serving entities are authorized to enter into. Even if a contract meets the emissions performance standard, ARB will need to identify the actual GHG emissions associated with the contract. Therefore, we recommend that all substitute power should have emissions attributed according to the source of the substitute power, whether specified or unspecified.
A. Unspecified Sources
The Joint Staff recommends that default emission factors be used for purchases from CAISO and for purchases from other unspecified sources, with separate default emission factors for the CAISO markets, purchases from other unspecified sources in California, purchases from unspecified sources in the Pacific Northwest, and purchases from unspecified sources in the Southwest. We recommend, instead, that a single regional default emission factor be used at this time for all purchases from unspecified sources.
The default emission factor that Staff recommends for real-time purchases from the CAISO would be based on the emissions from hydro and natural gas units that can be ramped quickly. The Joint Staff report recommends a split of 90 percent gas and 10 percent hydro, resulting in a default factor of 900 lbs CO2e/MWh. For the CAISO's Integrated Forward Market, the Joint Staff report expects that the market will include bids from all fuel sources but recommends a default emission factor of 1,000 lbs CO2e/MWh, based on an assumption that natural gas will be the principal marginal resource.
Several parties urge adoption of a single default emission factor for the CAISO real-time and forward markets. Parties believe that different emission factors for the different pools would give market participants incentives and opportunities to enter into transactions that would undermine the efficient operation of electricity markets and would reduce the accuracy of these emission rates over time. The CAISO recommends that the Commissions adopt the same emission factor for the real-time market and the Integrated Forward Market when it becomes operational, and that the emission factor be between 1,000 and 1,100 lbs C02e/MWh.
The Joint Staff recommends that power from in-state unspecified sources be assigned the average 2005 emission factor for all California natural gas units. Staff reports the rounded emission factor to be 1,000 lbs CO2e/MWh.
The Joint Staff recommends that default emission factors for power obtained from unspecified out-of-state sources be calculated for the Southwest and Pacific Northwest regions by first removing from the calculation all power purchased from specified sources (whether purchased by California entities or by entities in other states). A marginal method then would be used to calculate a regional average emission factor based on the historical and future probable dispatch patterns of the region. The Joint Staff report concludes that power from unspecified sources in the Southwest is 90 percent natural gas and 10 percent coal, with a weighted average emission factor of 1,075 lbs CO 2 e/MWh. Based on its hybrid analysis, the Joint Staff report characterizes power from unspecified sources in the Northwest as 66 percent hydro and 22 percent natural gas, with small amounts of coal, nuclear, and renewables. On that basis, the Joint Staff obtained a Northwest default emissions factor of 419 lbs CO2e/MWh.
Several parties dispute the default emission factor that the Joint Staff recommends for unspecified purchases from the Northwest. Some of these parties object that "unintended consequences" would occur because the Southwest default emission factor would be more than twice the size of the default emission factor that the Joint Staff recommends for the Northwest. These parties believe that this difference would provide incentives for parties to enter into transactions to hide high-emission sources located in the Southwest by moving power through California to the Northwest and then back into California. They suggest further that sellers could hide high-emission sources located in the Northwest by selling power from such sources into the Northwest power pool, with the power then resold as pool power, which would be attributed the default emission factor for the Northwest. In their view, either situation would reduce the accuracy of reported GHG emissions associated with serving California load and could also increase congestion on an already-constrained transmission system.
The Oregon Public Utility Commission and the Oregon Department of Energy (Oregon) and the State of Washington, Department of Community, Trade and Economic Development (Washington) express concerns that the methodology used in the Joint Staff proposal to develop a default emission factor for unspecified sources in the Northwest is inconsistent with the methodology currently used in Oregon and Washington. They contend, specifically, that the use of inconsistent methodologies in the Northwest and California would result in double-counting of hydropower. Oregon and Washington assert that hydropower in their states is used primarily to serve local or regional loads and that thermal power (coal and gas) is exported to serve load in California. In 2005, Oregon and Washington determined that the emission factor for the "net system mix" of electricity available for export from their region was 1,062 lbs CO2e/MWh.
The Community Environmental Council and DRA propose interim Northwest default emission factors that are closer in value to the default emission factor that the Joint Staff proposes for the Southwest.
SCPPA argues that the Joint Staff's recommended method of basing the Northwest default factor, in part, on historical sales is not consistent with the "pure" marginal approach that the Joint Staff uses to calculate the default emission factor for the Southwest. SCPPA asserts that, if marginal economic dispatch modeling were used to calculate the Northwest default emission factor, this would indicate that the cheapest resources (hydro) would be used to serve native load in the Northwest and that more expensive resources (coal and gas) would be used to serve load in California. The resulting default emission factor would be larger than the Joint Staff recommends. SCPPA argues that this larger emission factor would eliminate incentives to hide higher-emission resources in the Southwest.
Calpine Corporation (Calpine) and NRDC/UCS urge adoption of higher default emission factors than those recommended by the Joint Staff, for both the Southwest and the Northwest, in order to encourage retail providers to use less power from unspecified sources and to encourage retail providers to contract with low- and zero-emission resources. Calpine recommends that default emission factors should represent emissions from the highest emitting unit in the region. NRDC/UCS recommend that the emission factor for all natural gas plants be set at the emission factor for the least efficient natural gas plant (1,640 lbs CO2e/Mwh).
PG&E contends that insufficient information and data are presented in the Joint Staff's proposal to determine whether the proposed default emission factors are accurate, fair and verifiable. PG&E recommends that the reporting protocol be adopted without specific default emission factors and further workshops be scheduled to discuss calculation of emission factors.
In setting a default emissions factor, we are persuaded to use a higher, conservative value. We agree that setting high regional default emission factors at this time for unspecified sources would further, rather than hinder, the goal of accurate reporting. As several parties, including Environmental Defense (ED), NRDC/UCS, and Calpine, point out, high default emission factors would help discourage high-emitting resources characterizing themselves as unspecified resources. Conservatively estimated default emission factors would encourage retail providers to specify their sources of power, thus furthering the goal of accuracy in reporting and tracking emissions data. They also would reduce contract shuffling opportunities and encourage retail providers to seek low-or zero-emission power sources. By contrast, as Calpine points out, low default emission factors may actually increase purchases from high-emitting resources by encouraging such sources to market themselves as unspecified sources. Calpine notes further that, if the default emission factor is lower than the actual emissions, the calculated emissions would be understated and, thus, emissions reductions would be overstated.
For these reasons, we recommend that ARB use a uniform regional default emission factor for purchases from unspecified sources, and that it be set at a level that reduces incentives to claim unspecified sources. We recommend that ARB use 1,100 lbs CO2e/MWh as an interim regional default emission factor for purchases from unspecified sources. This value is close to the WECC regional average, and is higher than the emission factors for the most modern natural gas combined cycles and for hydropower and nuclear systems. Cleaner facilities and power systems will have the opportunity to have ARB verify and certify their emissions as a specified source with a known emissions factor.
As the Western states have now committed to developing a regional tracking system, California can best demonstrate its willingness to collaborate by not adopting at this time our own quantification system for default emission factors for imports from unspecified sources. Instead, we recommend that ARB use a uniform regional default emission factor for all unspecified sources on an interim basis. This would remove the incentive to arbitrage among regions based on differences in default emission factors, and, in this respect, would level the playing field among similar types of units in different regions. This interim default emission factor should be replaced with values derived from a common set of rules that will be developed by the Governors' Western Climate Initiative. We anticipate that this new tracking process will be in place before the start of the first GHG compliance year in 2012.
Several parties are concerned that the methods used to assign default emission values for unspecified sources should be consistent from 1990 forward so that artificial trends are not created solely due to changes in accounting conventions. ARB, Public Utilities Commission, and Energy Commission staffs have worked together to modernize the 1990 accounting to track as many specified sources, especially out-of-state coal units, as possible. This creates a greater degree of consistency than existed previously. But we cannot go back and create a 1990 Western regional tracking system to assign emissions to all power sources. Instead, we must rely on estimation techniques. Fortunately, interest in emissions related to electricity has been a topic of high policy interest starting in the late 1980s, so ARB can use information from that period to estimates 1990 emissions from the electricity sector.
We are aware that the choice of default emission factors may interact with computation of current emission responsibilities and proposals that some parties may have for allocation methods. This may be particularly true for those retail providers that currently purchase large amounts of power from unspecified sources. These issues will be addressed in the program design recommendations that we will send to ARB next year.
The proposed reporting and verification regulations in Attachment A are drafted to accommodate default emission factors that differ among the regions. Thus, if the regional collaboration yields region-specific default emission factors in the future, the regulations would not require modification in this respect. For now, however, we recommend a default emission factor of 1,100 lbs CO2e/MWh for use uniformly for purchases from unspecified sources in the Northwest, the Southwest, and California.
The Joint Staff suggests that separate GHG emission factors may be appropriate for purchases from generators that sell power on an unspecified basis from their own fleets of generating units. Asset-owning or controlling sellers could document their sources of power to avoid attribution of a regional default emission factor. We agree that entities that own or control generating assets should be allowed to request that ARB develop and apply a supplier-specific emission factor for their sales from unspecified sources.
The Joint Staff report describes that default emission factors could be estimated after a reporting period based on factors such as hydro availability and weather. Another option is to calculate ex ante emission factors that could be fixed at the start of a reporting period. The Joint Staff recommends that default emission factors be calculated on an ex ante basis to provide greater market certainty to retail providers.
Several parties support the Joint Staff recommendation in this regard. However, NRDC/UCS argue that ex post calculation of emission factors would provide a higher level of precision. In their view, if emissions factor were calculated ex post on an annual basis, retail providers would know the emissions factors established for the previous year and could use those emissions factors for planning purposes. They assert that, in most circumstances, emissions factors would be unlikely to deviate significantly from one year to the next. As a compromise, NRDC/UCS suggest that, to provide greater market certainty for retail providers, a hybrid approach could establish, on an ex ante basis, a range for allowable emission factors for each region. The specific emission factor would then be determined ex post on an annual basis, but would be limited by the adopted range.
We agree with Staff, as a general policy, that default emission factors should be calculated on an ex ante basis to provide greater market certainty to retail providers.
The Joint Staff recommend that default emission factors be updated periodically, possibly every three years. Several parties urge more frequent updating of emissions factors. One party suggests that the frequency with which default emission factors should be updated be resolved after more of the structure of GHG regulation has been resolved.
We recommend that ARB update the data inputs for default emission factors on an annual basis, at least initially, so that ARB, the reporting entities, and other market participants can better understand the implications of the adopted GHG regulations. The interim default emissions factors described above should be updated when either a regional tracking method is operational or ARB has collected sufficient data to document the validity of a revised method.
B. Retail Providers' Wholesale Sales
AB 32 governs statewide GHG emissions, including electricity consumed in California (including imports), and in-state generation that is exported out of California. In a load-based approach, retail providers would be responsible for the GHG emissions incurred to meet their retail load and for power generated in California and exported out of California. They would not be responsible in a load-based approach for the GHG emissions associated with power they sell or deliver through exchange agreements that is used to meet another retail provider's retail load. To avoid an incentive to mask exports by intermediary sales to marketers with a point of delivery in California, who could then export the power out of state, we require that retail providers document that in-state sales that are delivered to a point of delivery in California are in fact used to serve California load. Without such documentation, such sales would be treated as exports for purposes of GHG emission verification.
In a load-based approach, once a retail provider's own generation, power purchases, and related GHG emissions are known, GHG emissions must be attributed to the retail provider's wholesale sales and the emissions attributable to in-state sales must be deducted from the retail provider's emission responsibilities. The remaining GHG emissions represent the power used to serve the retail provider's in-state load and any sale of power that was exported from the state.
Retail providers may make sales from specified sources or deliver power from specified sources through the terms of an exchange agreement. If delivered to a counterparty located in California for use in meeting California load, the corresponding emissions would be removed from the provider's GHG responsibility. To adjust total emissions for sales and exchanges from specified sources, ARB would use source-specific emission factors, as described in Section V.B.1 above.
However, an adjustment may be needed to the manner in which emissions are attributed to certain sales from owned or partially-owned power plants, to address concerns regarding contract shuffling, as discussed in Section V.A. We recommend that ARB require that retail providers explain why sales from owned or partially-owned power plants were undertaken.13 We recommend that, if the power could not be delivered to the retail provider or the retail provider did not need the power during the hours in which it was sold for reasons such as because it had surplus power from its owned power plants and the specified plant was the marginal plant during the hours in which the power was sold, or if the power was from a California-eligible renewable plant with WREGIS certificates transferred to the buyer along with the power, ARB attribute emissions to the power sold based on the emission factor of the power plant. Otherwise, ARB should use the average emission factor of the retail provider's sources that are available for unspecified sales, as described in Section V.D.2. This recommendation would apply only to the portion of sales in excess of ten percent of the retail provider's proportional ownership-based share of the plant's total net generation.
For sales from all other specified sources, i.e., purchases from power plants that are not owned or partially-owned by the retail provider, we recommend that ARB attribute emissions to the sold power based on the emission attributes of the specified power plant.
The Joint Staff report proposes what it calls an "adjusted all-in" methodology for the attribution of GHG emissions to a retail provider's sales from unspecified sources. The Staff method would remove sources reported as serving the retail provider's own native load from its resource mix and then
would determine an average GHG emission factor for generation from the remaining owned assets and purchases. The retail provider's sales from unspecified sources would be assigned this average GHG emission factor. The Joint Staff suggest that retail providers be allowed to request that a more disaggregated calculation be performed if they believe that this averaging method does not reflect accurately the nature of their transactions. No parties commented on the Joint Staff's proposal to account for GHG emissions associated with sales from unspecified sources using the "adjusted all-in" method.
With some modifications, we adopt Staff's proposal to use the "adjusted all-in" method to calculate GHG emissions associated with retail providers' sales from unspecified sources. First, in addition to sources reported as serving native load, power that the retail provider sold or delivered pursuant to an exchange agreement from specified sources should be removed from the retail provider's resource mix before an average emission factor is calculated for power available for unspecified sales. Second, we limit and clarify the sources that a retail provider may claim as serving native load. Third, we modify Staff's proposal to recognize that the pool of power available for unspecified sales is likely to consist of both in-state and out-of-state resources. Therefore, only a portion of the sales made to out of state entities from this pool are exports. If emissions attributed to the reporting entity for exports were not adjusted to take this into account, the reporting entity's emission's responsibility for exports would be too high. In order to exclude the emissions associated with the power from out-of-state resources in the pool available for unspecified sales, the emissions resulting from the application of the emissions factor used for unspecified sales to sales to out-of-state entities must be further adjusted by the ratio of the emissions from in-state sources in the pool divided by of all emissions in the pool. This is done to avoid the emissions associated with power from out-of-state resources sold to out-of-state entities from being attributed to the reporting entity as exports from California.
As described above, the retail providers' GHG emissions responsibilities are adjusted for sales to other entities to meet California load. Sales of power to entities outside the state constitute exports, and emissions responsibilities for power generated in California and exported should be attributed to the selling party, in this case the retail provider.
Some parties argue that they should not be required to report electricity exported from California. SMUD argues that ARB should not consider the emissions associated with exports. It focuses on the language in Section 38530(b)(2), which provides that the GHG regulations shall account for
GHG emissions from all electricity consumed in the state whether generated in the state or imported. However, this argument ignores Section 38505(m), which
defines "statewide greenhouse gas emissions" as "the total annual emissions of greenhouse gases in the state, including all emissions of greenhouse gases from the generation of electricity delivered to and consumed in California . . . whether the electricity is generated in state or imported" (emphasis added). One purpose of the language beginning with the word "including" is to ensure that California's GHG regulatory scheme accounts for GHG emissions associated with electricity imported into California for consumption here. However, the part of the definition preceding the word "including" requires the regulatory scheme to encompass all greenhouse gases that are emitted in California. There is nothing in Section 38530(b)(2) that would exclude any in-state emissions or overrule the requirement of Section 38505(m). Accordingly, it is proper for the reporting scheme to include electricity that is generated within the state, whether it is consumed in California or exported out of California.
SMUD contends that the recommended adjustment that would subtract energy sold to counterparties within California from total emissions, but not energy sold to counterparties outside of California. SMUD states that this difference would be an incentive to sell energy to in-state entities and may create an impediment to wholesale sales to out-of-state entities potentially in violation of the dormant Commerce Clause and/or the Federal Power Act. Under a load-based (i.e., a retail provider-based) reporting system, emissions generated within California by retail providers should be accounted for by one retail provider or another. Where such power is sold for consumption in California, the associated emissions can be subtracted from the emissions of the retail provider that generated the power. On the other hand, where power is exported out of the state, it would not be reported by another retail provider, and therefore the associated emissions should not be subtracted from the gross emissions of the retail provider that generated the power. This is not a matter of discriminating against sales to non-California counterparties. Rather, it is an accounting method to help ensure that all California emissions are reported by a retail provider, whether the power is sold in-state or out-of-state. Because there is no discrimination against sales to other states, there is no violation of the Commerce Clause.14
SMUD and other parties stress a concern with possible compliance obligations for exports. These parties argue that holding them accountable for emissions related to exports would put a heavier burden on the electricity sector than on any other sector. They contend that contributing emissions associated with exports to California would be contrary to the concept of integrating GHG emission tracking among the states.
While we are aware of the parties' concerns regarding potential double counting of GHG emissions associated with exports if regional GHG regulations develop, AB 32 requirements encompass exports of power generated in California. As a result, we recommend that ARB collect information regarding exports and verify emissions associated with those exports, as detailed in Attachment A. We will address later in this proceeding the manner in which GHG emissions associated with exports should be treated for purposes of AB 32 compliance.
C. Reporting Requirements for Marketers
Section 3 of the reporting Protocol in Attachment A contains recommended reporting requirements for marketers that import electricity into California or export electricity from California to other states. Data regarding marketers' imports that are used to meet California load would be needed if a first-seller regulatory approach is adopted. Data regarding marketers' exports would be needed under a load-based approach. We recommend that ARB attribute emissions to marketers' imports used to meet California load and exports in a manner similar to the way in which emissions would be attributed to retail providers, as detailed in Section 3 of Attachment A. We also recommend that marketers be required to report imports into California that terminate in a location outside of California, i.e., that are wheeled through California.
While AB 32 would not regulate emissions associated with power wheeled through California, information regarding the quantity of wheeled electricity would facilitate cross-checking and the derivation of control totals, if the deliverer/first-seller approach is chosen for the electricity sector. If the deliverer/first-seller approach is not chosen, the additional reported information may still be helpful to ARB.
2 Joint Staff refers to this concern as "contract shuffling."
3 For power plants located in California, emissions associated with exports are not subtracted, since AB 32 requirements encompass exports of power generated in California.
4 By "large hydro plant," we mean any hydroelectric plant larger than 30 megawatts that is not a California-eligible renewable plant.
5 As discussed in Section V.C, we recommend that ARB use a uniform regional default emission factor at this time. We expect that default emission factors for each region will be set at a later date.
6 In essence, Sempra's argument is that it may be disadvantaged because existing low-GHG emission power plants may not be able to get the full economic benefit created by AB 32's GHG cap. This argument has by and large been eliminated by our recommendation to narrow the use of default emission rates to purchases under new contracts where the electricity is generated by existing nuclear or large hydro facilities. (And even as to those facilities, the default rate would not apply if the purchaser can show a real reduction in GHG emissions.) But to the extent that some generator still might not realize the same economic benefits as a result of the implementation of AB 32 as the owner of a new plant, this would still only establish that two differently situated entities have received different financial benefits as a result of the new law. Sempra has made no showing that this would illegally discriminate against interstate commerce or otherwise be illegal.
7 We note that, if a reporting retail provider sells its ownership share or the power plant does not operate, the retail provider would no longer be responsible for emissions from the power plant.
8 We recommend that power obtained or delivered through exchange agreements be treated as a purchase or sale, respectively, for purposes of GHG accounting.
9 D.07-01-039 emphasized that the "determination on how to treat null renewable power and associated RECs is specific to the application of [the] adopted interim [emission performance standard]. This determination in no way guarantees that null renewable power will be assigned a zero or low GHG emissions value in the context of the Procurement Incentive Framework we are implementing in Phase 2 of this proceeding, or the statewide GHG emissions limit adopted by the Legislature in AB 32." (D.07-01-039, mimeo. at 127.)
10 D.07-01-039, mimeo. at 134-151.
11 Ibid., at 146.
12 Ibid., at 148.
13 As explained in Section V.A.3, contractual arrangements in which the purchasing party has a contractual entitlement to a specified percentage of the output of a power plant would be treated, for purposes of GHG accounting, as an ownership interest in the power plant.
14 SMUD does not explain why, in its view, this portion of the reporting protocol might violate the Federal Power Act.
