Common use of FUTURE LCBF METHODOLOGY IMPROVEMENTS Clause in Contracts

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s methodology has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have provided incremental improvements to the methodology. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals or the transparency with which potential counterparties can view the evaluation process. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs to be demonstrated within the text of the proposal and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected); • Including the scoring guidelines for all twelve criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocol, rather than a website reference, or within Appendix K; • Describing in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issues; • Editing solicitation materials to emphasize the need for out-of-state projects to provide both busbar contract price and price premium for CAISO delivery, and to clarify for projects proposing to interconnect in non-CAISO control areas in the state the need to explicitly identify how the power would be moved to the CAISO; • Stating within the protocol the types of relevant costs (such as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance services; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing to deliver at distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx points; • Editing the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions for the short list (or, alternatively, relabeling those two preferences as evaluation criteria); and • Editing the solicitation protocol to provide a xxxxxx description of how proposals for utility ownership (including PSAs, PPAs with buyout options, and joint development or joint development) are evaluated and what characteristics of such projects would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division of the outcome for proposals located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principles.”16 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. As was feared by a PRG member, the special outreach efforts, despite the careful wording of the solicitation materials, appear to have given the misimpression to some developers that a preference would be given to Imperial Valley developers. Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset the deadline to noon, in order that, on one hand, the PG&E team and IE can begin the Offer Opening process in the morning as package deliveries start to arrive, while on the other hand out-of-town Participants will not feel pressured to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, in order to improve the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.17

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s methodology has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have provided incremental improvements to the methodology. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals or the transparency with which potential counterparties can view the evaluation process. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs to be demonstrated within the text of the proposal and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected); • Including the scoring guidelines for all twelve criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocol, rather than a website reference, or within Appendix K; • Describing in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issues; • Editing solicitation materials to emphasize the need for out-of-state projects to provide both busbar contract price and price premium for CAISO delivery, and to clarify for projects proposing to interconnect in non-CAISO control areas in the state the need to explicitly identify how the power would be moved to the CAISO; • Stating within the protocol the types of relevant costs (such as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance services; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing to deliver at distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx points; • Editing the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions for the short list (or, alternatively, relabeling those two preferences as evaluation criteria); and • Editing the solicitation protocol to provide a xxxxxx description of how proposals for utility ownership (including PSAs, PPAs with buyout options, and joint development or joint development) are evaluated and what characteristics of such projects would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division of the outcome for proposals located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principles.”16 ”17 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. As was feared by a PRG member, the special outreach efforts, despite the 17 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 careful wording of the solicitation materials, appear to have given the misimpression to some developers that a preference would be given to Imperial Valley developers. Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset the deadline to noon, in order that, on one hand, the PG&E team and IE can begin the Offer Opening process in the morning as package deliveries start to arrive, while on the other hand out-of-town Participants will not feel pressured to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, in order to improve the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.17cutoff.18

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s The methodology employed by PG&E has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have This process has provided incremental improvements to the methodologymethodology over time. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals Offers or the transparency with which potential counterparties Participants can view the evaluation process, some of which were suggested in feedback sessions by Participants. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, sense that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced help reduce wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of Reviewing the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs is required to be demonstrated within the text of the proposal and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected)obtain top scores in each criterion; • Including the scoring guidelines for all twelve 11 criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocolin Attachment K, rather than a website reference, or within Appendix K; • Describing with commentary on what it takes to obtain top scores in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issueseach category; • Editing the solicitation materials to further emphasize the need for out-of-state projects to provide both busbar contract a full price and price premium for at a CAISO delivery, and to clarify for projects proposing to interconnect in non-CAISO control areas in delivery point that the state the need to explicitly identify how the power developer would be moved willing to write into a PPA, rather than a busbar price outside the CAISO; • Stating within Modifying solicitation materials to clarify that the protocol developer must provide a copy of the types of relevant costs (such most recent interconnection study or executed interconnection agreement that will serve as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from basis for estimating a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance servicestransmission adder for network upgrades; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing to deliver at distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx points; • Editing Revising the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions decisions. In particular, it would be key to make as clear as possible within the solicitation protocol itself what PG&E’s preferences for the short list (oron-line date are, alternatively, relabeling those two preferences as evaluation criteria)seeing that many Participants completely failed to notice this; and • Editing the both the public and non-public solicitation protocol protocols to provide a xxxxxx description of how proposals Offers for utility ownership (including PSAssites for development will be evaluated, PPAs with buyout optionswhat the basic requirements for eligibility are, and joint development or joint development) are evaluated what specific evaluation criteria will be used, and what characteristics of such projects offered sites would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities The ownership team should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division provide clearer internal documentation of the outcome for proposals located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” how it made its selection and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principlesrejection decisions.”16 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. As was feared by a PRG member, the special outreach efforts, despite the careful wording of the solicitation materials, appear to have given the misimpression to some developers that a preference would be given to Imperial Valley developers. Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset the deadline to noon, in order that, on one hand, the PG&E team and IE can begin the Offer Opening process in the morning as package deliveries start to arrive, while on the other hand out-of-town Participants will not feel pressured to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, in order to improve the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.17

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s methodology has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have provided incremental improvements to the methodology. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals or the transparency with which potential counterparties can view the evaluation process. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs to be demonstrated within the text of the proposal and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected); • Including the scoring guidelines for all twelve criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocol, rather than a website reference, or within Appendix K; • Describing in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issues; • Editing solicitation materials to emphasize the need for out-of-state projects to provide both busbar contract price and price premium for CAISO delivery, and to clarify for projects proposing to interconnect in non-CAISO control areas in the state the need to explicitly identify how the power would be moved to the CAISO; • Stating within the protocol the types of relevant costs (such as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance services; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing to deliver at distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx points; • Editing the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions for the short list (or, alternatively, relabeling those two preferences as evaluation criteria); and • Editing the solicitation protocol to provide a xxxxxx description of how proposals for utility ownership (including PSAs, PPAs with buyout options, and joint development or joint development) are evaluated and what characteristics of such projects would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division of the outcome for proposals located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principles.”16 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. As was feared by a PRG member, the special outreach efforts, despite the careful wording of the solicitation materials, appear to have given the misimpression to some developers that a preference would be given to Imperial Valley developers. Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset the deadline to noon, in order that, on one hand, the PG&E team and IE can begin the Offer Opening process in the morning as package deliveries start to arrive, while on the other hand out-of-town Participants will not feel pressured to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of 17 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, in order to improve the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.17cutoff.18 18 For the actual Offer in question, the valuation of the straight PPA with no buyout option exercise was much lower but still above the value cutoff so the concern Xxxxxx expresses is relevant for future solicitations but not for the current situation. With the introduction of the Project Viability Calculator as a tool to assess the likelihood of projects achieving successful operation come some opportunities for the Energy Division and the IOUs to evaluate its use and possibly implement improvements for the future. • There is an opportunity to refine the scoring guidelines for the Calculator. It became evident that reasonable people scoring offers could arrive at different interpretations of the guidelines, and that there are gray areas that require judgment. For example, one scorer might regard a developer’s prior experience constructing and operating small photovoltaic installations that reside on a customer’s premises beyond the meter as the basis for a high score on Project Development Experience, while another scorer might view these projects as not representing “wholesale generation” and therefore assign a zero score.19 Similarly, one scorer might view a photovoltaic project for which the developer estimates direct net irradiance based on publicly available government-published data for a nearby weather station as deserving a score of 10 for Resource Quality, while another scorer might assign a 5 to the same Offer because it does not cite a third-party resource assessment or measured irradiance at a comparable photovoltaic facility in the region. • Even if the text of the scoring guidelines is not revised, there is an opportunity for the PG&E team to move towards a more uniform interpretation of the guidelines among scorers. This might be as simple as a pre-RFO internal workshop to discuss gray areas in the guidelines and come to some common understanding of how best to deal with ambiguities. Or it might be a chapter in PG&E’s internal protocol for Project Viability that outlines additional guidance to clarify how the team might best deal with ambiguities or gray areas in the Calculator scoring guidelines. In the 2009 RFO, the PG&E team made substantial efforts to achieve consistency in scoring, and some of these ambiguities became evident only after internal review of preliminary scores led the team to revise them to improve the consistency of scoring; it is clearly a challenge for any team of scorers to approach perfect uniformity. • The Calculator as currently constructed assigns a score for Permitting based on whether the developer has applied for permits, has achieved data adequacy for permit applications, or has obtained its permits. The score does not reflect the expected difficulty of obtaining permits. Xxxxxx suggests that the Energy Division consider including some judgment about the degree of difficulty of successful permitting. Some Offers were evaluated to be at risk for project failure due to serious environmental concerns that could lead to permitting failure, despite achieving moderately high viability scores using the Calculator. 19 At least one Participant noticed this feature of the scoring guidelines and asserted that its prior experience installing customer premises equipment beyond the meter constitutes wholesale generation experience. Xxxxxx questions the relevance of PG&E’s methodology for scoring proposals for Portfolio Fit. The CPUC has very clearly enunciated that IOUs should use a methodology that leads to selection of least-cost, best-fit resources. However, Xxxxxx notes that the degree to which a proposed new resource fits well or badly into PG&E’s existing and planned portfolio of supply resources is largely captured already in the valuation methodology. For example, the increased value of power delivered in super-peak hours and peak seasons vs. the decreased value of power delivered in night hours and off-peak seasons is captured by the valuation algorithm. The methodology to value RA benefits also captures the unique contribution of generators in peak hours when resources are most needed to meet reliability needs. PG&E’s valuation methodology is designed to capture value of the flexibility of dispatchable resources over as-available resources. So to a large extent the valuation methodology has been constructed to reflect in dollar terms the value of both the firmness and time-of-delivery characteristics of Offers. Also, the existing and prior methodologies for evaluating Portfolio Fit in PG&E’s RPS RFOs do not directly address the question of when baseload resources will be needed for the portfolio or when peaking resources will be needed. (Note that the bilaterally negotiated resources are not scored with the same methodology as proposals in the RPS solicitation). Therefore Xxxxxx surmises that most of the relevant features of fit with PG&E’s portfolio needs are already captured by PG&E’s valuation methodology, and scoring separately for Portfolio Fit is largely redundant. SCE appears to have captured its Fit evaluation within its valuation model and apparently doesn’t employ a separate score for Fit. It is hard to imagine a renewable resource whose Portfolio Fit characteristics are so superior that a reasonable person would select it for the short list despite deficiencies in value or viability, or a resource so inferior in Portfolio Fit (say, a non-dispatchable generator that produces power only between 1 a.m. and 4 a.m. in the springtime) that it would be rejected from the short list despite superior value and viability. Xxxxxx is not aware of any short list selections or rejections by PG&E that have been motivated primarily by a Portfolio Fit score. So Xxxxxx suggests the possibility that Portfolio Fit scoring be dropped in PG&E’s future solicitations unless such a special case or a need for a tie-breaker arises.

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s methodology has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have provided incremental improvements to the methodology. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals or the transparency with which potential counterparties can view the evaluation process. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs to be demonstrated within the text of the proposal and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected); • Including the scoring guidelines for all twelve criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocol, rather than a website reference, or within Appendix K; • Describing in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issues; • Editing solicitation materials to emphasize the need for out-of-state projects to provide both busbar contract price and price premium for CAISO delivery, and to clarify for projects proposing to interconnect in non-CAISO control areas in the state the need to explicitly identify how the power would be moved to the CAISO; • Stating within the protocol the types of relevant costs (such as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance services; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing to deliver at distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx points; • Editing the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions for the short list (or, alternatively, relabeling those two preferences as evaluation criteria); and • Editing the solicitation protocol to provide a xxxxxx description of how proposals for utility ownership (including PSAs, PPAs with buyout options, and joint development or joint development) are evaluated and what characteristics of such projects would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division of the outcome for proposals located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principles.”16 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. As was feared by a PRG member, the special outreach efforts, despite the careful wording of the solicitation materials, appear to have given the misimpression to some developers that a preference would be given to Imperial Valley developers. 16 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset the deadline to noon, in order that, on one hand, the PG&E team and IE can begin the Offer Opening process in the morning as package deliveries start to arrive, while on the other hand out-of-town Participants will not feel pressured to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, in order to improve the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.17

FUTURE LCBF METHODOLOGY IMPROVEMENTS. PG&E’s The methodology employed by PG&E has undergone repeated refinement, motivated both by internal choices within the utility and external impetus by the regulator. Most of these have provided incremental improvements to the methodology. Xxxxxx can at this point only suggest a few modest changes that may further improve the means by which PG&E evaluates proposals Offers or the transparency with which potential counterparties Participants can view the evaluation process. One set of suggestions would seek to address the sense, arising from debriefing non- shortlisted Participants, that comprehension of how PG&E evaluates and selects Offers among the developer community could be improved. This could lead to reduced wasted effort on the part of developers in promoting projects that are unlikely to be selected, and reduce the amount of wasted effort within the utility as it attempts to analyze Offers with poor viability and low value. Some ideas could include: • Including a walk-through of the scoring guidelines for the Project Viability Calculator in the bidders’ conference, to explain what specifically needs to be demonstrated within the text of the proposal Offer and why it affects the viability score (e.g. identifying whether and how site control has been achieved, and naming the EPC contractor if it has been selected); • Including the scoring guidelines for all twelve criteria used in the Calculator and not just the EPC Experience criterion within the body of the solicitation protocol, rather than a website reference, or within Appendix K; • Describing in the bidders’ conference which clusters in PG&E’s service territory are the most congested, perhaps in terms of ranking by the proxy $/kW cost that is provided by PG&E’s TRCR for network upgrade costs that would be allocated to generators choosing to interconnect there, based on the total MW range of possible new generation that was analyzed for the TRCR. This could give developers more of a sense of which sites are disadvantaged by congestion issues; • Editing the solicitation materials to emphasize the need for out-of-state projects to provide both a busbar contract price and a price premium for CAISO deliverydelivery to the CAISO, and to clarify that for projects proposing to interconnect in non-CAISO control areas in within the state the need to explicitly identify how the power would be moved to the CAISOa CAISO interface; • Stating within the protocol the types of relevant costs (such as firm transmission, imbalance costs, operating reserves, and shaping and firming fees if appropriate) that would need to be covered by the price premium to move power from a foreign control area to the CAISO, in an effort to motivate Participants to provide more accurate, more realistic, and more complete information about how they would deliver their energy, or alternatively educating them about the disadvantages of siting an intermittent generation project in a control area whose operator will not support proposed exports to the CAISO with operating reserves and imbalance services; • Clarifying the extent to which transmission adders would be added to the economics of out-of-state projects proposing that propose to deliver at far distant substations such as Moenkopi or Four Corners, despite the fact that these serve as XXXXX xxxxxxxxxx CAISO scheduling points; • Editing the solicitation materials to clarify that, in addition to the various evaluation criteria, PG&E will use its preferences regarding delivery point and timeliness of commercial operation date to make selection and rejection decisions for the short list (or, alternatively, relabeling those two preferences as evaluation criteria); and • Editing the solicitation protocol to provide a xxxxxx description of how proposals Offers for utility ownership (including PSAs, PPAs with buyout options, and joint development or and/or joint development) are evaluated and what unique characteristics of such offered projects would render them attractive or unattractive to the utility as candidates for ownership. • In the Decision approving the IOU’s 2009 procurement plans, the CPUC specified that the utilities should conduct special outreach activities to highlight the unique opportunity to develop new renewable generation in the Imperial Valley now that the transmission investment in the Sunrise Powerlink is approved (by, for example, ordering that each IOU conduct a special bidders’ conference to highlight the Imperial Valley opportunity). Similarly, the Decision called for specific monitoring by the Energy Division of the outcome for proposals Offers located in the Imperial Valley in the 2009 RFOs. However, the Decision also stated that “Monitoring does not mean that preference is given to Imperial Valley developers” and “Providing a preference for Imperial Valley resources (which is denied to others) generally conflicts with LCBF principles.”16 ”18 Based on debriefing sessions with non-shortlisted Participants, it is evident that some developers understood the special outreach and special monitoring to imply that Offers for projects in the Imperial Valley would receive special preference by PG&E. 16 18 California Public Utilities Commission, Decision 00-00-000, “Decision Conditionally Accepting 2009 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements”, June 8, 2009, pages 16, 17 In reviewing the solicitation materials, including the presentation at PG&E’s special bidders’ workshop on the Imperial Valley, Xxxxxx found no statement or suggestion that the utility would provide any special preference to Imperial Valley renewable projects. (The materials did state that PG&E encourages Offers for projects located within the Imperial Valley, and that the special conferences were intended to increase the likelihood that developers will propose viable, competitively priced projects in the Imperial Valley). As was feared by a PRG memberat least one member of the PRG, the special outreach efforts, despite the careful wording of the solicitation materials, appear to have given the led to a misimpression to among some developers that a preference would be given to Imperial Valley developers. Xxxxxx’x suggestion is that, should the situation arise again to conduct special CPUC-directed outreach for particular opportunities, that the solicitation materials also emphasize that LCBF principles will be followed in PG&E’s evaluation and selection procedures and that no special preference will be provided (unless of course the CPUC decides in the future to mandate a preference). • The offer submittal deadline stated in the solicitation protocol was 10 a.m. Pacific Time on August 24, 2009. Xxxxxx wonders whether in future a better choice might be to reset In the 2008 RPS solicitation, the utility was plagued by Offers that were delivered the day after the deadline date. The choice of a specific deadline of 10 a.m. was intended to noon, in order that, on one hand, the PG&E team avoid that outcome. Xxxxxx notes that package delivery services such as FedEx and IE can begin the Offer Opening process in the morning as package deliveries start United Parcel Service offer an early next- business day service that is supposed to arrive, while on the other hand out-of-town Participants will not feel pressured achieve delivery by 8 a.m. to hand their Offers to the team in person at some incremental expense. • Use the discount rate employed by the Energy Division in calculating the Market Price Referent, which is based on an estimate of the cost of capital for power developers, rather than a discount rate based on PG&E’s authorized cost offices in San Francisco. Some Participants took the extraordinary step of capital. Xxxxxx believes that given the variety of risks that face renewable project development (permitting, site control, interconnection, equipment procurement, financing, etc.) it is more appropriate flying to discount the expected future benefits and costs of the projects using a higher discount rate representative of the riskier independent power industry, rather than the lower discount rate of a regulated monopoly. One effect of using the lower utility discount rate is that it overemphasizes the value to ratepayers of the last decade of project operation, including years after 2020, for which the extrapolation of power market pricing provides a picture of valuation that is tenuous at best. Xxxxxx believes that developers appropriately use a higher discount rate than PG&E’s authorized cost of capital in making their decisions about contract price, despite the fact that once contracted the project revenue is essentially secured by PG&E’s credit. • Investigate the extent to which the CAISO will actually grant PG&E’s customers the Resource Adequacy value for generation that interconnects through SGIP. Xxxxxx is concerned that assuming full RA value for small projects that will not undergo the scrutiny of a CAISO deliverability assessment may lead to a situation where SGIP- based projects are shortlisted assuming they will deliver RA value to ratepayers but later fail to actually deliver that value. While both the CAISO and CPUC are aware of this situation and wish to seek a solution, a solution is not guaranteed. • Require projects that are seeking CAISO interconnections through the LGIP to state explicitly in San Francisco with their Offer whether they are pursuing energy-only status and avoiding the costs associated with network upgrades for deliverability. Such projects should not be credited with RA value in the evaluation, and it would be better to identify these situations early, as well as to monitor for those projects that switch to energy- only status after the short list is finalized so that their value to ratepayers is diminished with no concomitant reduction in contract price. • Codify the procedures for assigning non-PG&E transmission adders to projects into a (nonpublic) protocol. The valuation methodology would benefit from an effort to achieve greater internal clarity and consistency in how decisions are made for assigning transmission adders for moving power from other states to the CAISO, for delivering power at CAISO interface points outside PG&E’s territory, and delivering into non-CAISO control areas. It would be particularly helpful to codify precedents that have been made in prior RFOs regarding when and where to use TRCR adders vs. the cost of alternative commercial arrangements, materials in order to improve ensure that their delivery met the consistency with which Participants and proposals are treated. • Require that PG&E’s subcommittee on ownership eligibility review all shortlisted proposals that involve utility ownership, including PPAs with buyout options. Xxxxxx noted that one proposal was shortlisted because the variant with a buyout option proposed an attractively low strike price for PG&E to purchase the facility at its option. The valuation of that buyout option variant was quite high among the rankings, but the valuation of the Offer if the buyout option were not exercised was substantially lower. Xxxxxx was concerned that there was apparently no buy-in required of the team responsible for considering such ownership for the PPA-with- buyout-option variant. This creates the possibility that a PPA-with-buyout Offer would be short-listed based on its attractive buyout price but that the facility itself would turn out later not to meet PG&E’s criteria to own the project and the straight PPA valuation would fail to meet the value cutoff.1710