4. Discussion
4.1. Is SCE's ownership of its interest in Four Corners no longer necessary or useful in the performance of its duties to the public?
It is undisputed that SCE's ownership of its interest in Four Corners is no longer necessary or useful in the performance of its duties to the public. As discussed below, divestiture will not impair the reliability of the California electric supply and is consistent with SB 1368 mandating a greenhouse gas EPS and the Commission's decisions establishing and implementing the EPS for SCE.
4.2. Will divestiture of SCE's interest impair the reliability of the electric supply?
It is undisputed that SCE's share of Four Corners' output is not needed to maintain the reliability of the California electric supply. Pub. Util. Code § 362 requires the Commission to:
...ensure that facilities needed to maintain the reliability of the electric supply remain available and operational, consistent with maintaining open competition and avoiding an overconcentration of market power. In order to determine whether the facility needs to remain available and operational, the commission shall utilize standards that are no less stringent than the Western Electricity Coordinating Council [WECC] and North American Electric Reliability Council [NERC] standards for planning reserve criteria.
The WECC and NERC standards for planning reserve criteria are incorporated into the California Independent System Operator (CAISO) and Commission policies and regulations establishing and enforcing planning reserve requirements. The CAISO has not designated Four Corners as a "must-run" facility and has consented to the withdrawal of SCE-owned, Four Corners-related transmission facilities from CAISO's operational control. SCE's planned transaction closing date is October 1, 2012, allowing SCE's divestment of Four Corners to be taken into account in the Commission's review of SCE's Track II Bundled Procurement Plan that is to be submitted later this year in the 2010 Long Term Procurement Plan proceeding (Rulemaking 10-05-006.) Furthermore, the sale agreement provides that, in the event that the transaction closes before October 1, 2012, SCE has the option to retain the capacity rights associated with Four Corners and, if SCE exercises that option, APS must submit all bids for energy, self-schedules, and self-provision of ancillary services for SCE's interest in Four Corners in the CAISO day-ahead market, hour-ahead scheduling process, and real-time market, as required for SCE to satisfy the requirements of California's Resource Adequacy program.
4.3. Is the divestiture pursuant to the Purchase and Sale Agreement reasonable?
4.3.1. Is the divestiture consistent with EPS?
It is undisputed that divestiture of SCE's interest in Four Corners is consistent with SB 1368 mandating a greenhouse gas EPS and the Commission's decisions establishing and implementing the EPS for SCE. Four Corners does not meet the adopted EPS. Decision (D.) 10-10-016 denied SCE recovery in rates of capital expenditures in Four Corners forecasted to be incurred beginning January 1, 2012, and directed SCE to conduct a study on the feasibility of maintaining its interest in Four Corners after the end of 2011, to report on its study, and to propose a course of action in its 2012 general rate case. (D.10-10-016, Ordering Paragraphs 2 and 3.) SCE's divestiture of its interest in Four Corners will resolve the tension between the EPS rules (prohibiting SCE from making certain life-extending expenditures for Four Corners) and SCE's potential contractual obligations under the Four Corners Project Operating Agreement (funding certain pro rata capital investments as a co-owner). Moreover, SCE's exit from coal-fired generation ownership in 2012 is consistent with the Commission's requirement that it do so by 2016.
4.3.2. Is the value of the Sale Agreement reasonable?
Under a reasonable range of assumptions, the value of the Asset Sale and Purchase Agreement (Sale Agreement) will hold SCE ratepayers economically indifferent to a sale before the expiration of the Operating Agreement.5 The Sale Agreement provides for a $294 million purchase price, which is correspondingly adjusted upward for each month the closing is accelerated before October 1, 2012, and adjusted downward for each month the closing is delayed after October 1, 2012, reflecting the need for SCE to replace Four Corners' low cost baseload power with probably more expensive alternatives. The Sale Agreement provides for APS to assume SCE's obligation, if any, under the Operating Agreement related to the installation of selective catalytic reduction technology or other capital expenditures that SCE cannot fund under California law. The Sale Agreement provides that the purchase price will be increased by the amount of capital expenditures funded by SCE during 2010 and 2011 in excess of its share of the owners' approved 2010 and 2011 capital budgets for the plant, plus the capital expenditures funded by SCE during 2012 and thereafter until the closing date (minus any related depreciation). The undisputed evidence demonstrates that, as co-owner and sole operator of the plant, APS is the most viable of potential buyers of SCE's minority interest in Four Corners. Also, the Co-Tenancy Agreement grants APS (and the other co-owners) a right of first refusal to a potential sale.
In its opening brief on CEQA issues, EDF argues that the Commission should require SCE to monitor and report emissions from Four Corners Units 4 and 5 and/or condition the sale on APS's commitment to retire Units 1 through 3. To the extent that EDF means to suggest that such conditions are required in order to support a finding that the sale is reasonable, EDF's argument is untimely; pursuant to the schedule established in this proceeding, the time for prepared testimony and evidentiary hearing on this issue was April 1, 2011, and May 23 through 24, 2011, respectively (see scoping memo), and the time for opening and reply briefs on this issue was June 14 and 24, 2011. (Tr. 185:5-23.) In any event, as discussed in Part 4.6, below, the IS/ND determines that the sale will not have any significant adverse environmental impacts; EDF does not persuade us that imposing the costs of monitoring for a non-existent environmental impact on SCE's ratepayers, or risking the transaction's failure in the event that APS or SCE declines to accept its proposed conditions, is in SCE's ratepayers' or the public's interest.6
Under the totality of these circumstances and based on the ratemaking treatment of the gain on sale as discussed in Part 4.5 below, we find the value of the Sale Agreement to be reasonable.
4.4. Are SCE's proposed 2012 capital expenditures in Four Corners reasonable?
Pub. Util. Code § 8341, which enacted the California EPS, provides that load-serving entities may not enter into a long-term financial commitment unless any baseload generation supplied under such long-term financial commitment complies with the greenhouse gas EPS. Pub. Util. Code § 8340(f) defines "long-term financial commitment" to include "new ownership investment" in base load generation. These statutes do not define "new ownership investment." However, D.07-01-039, which adopts the interim EPS rules, defines "new ownership investments" to include any investment that is intended to extend the life of one or more units of an existing baseload power plant for five years or more or results in a net increase in the rated capacity of the power plant. (D.07-01-039 at 5 and Finding of Fact 33.)
D.10-10-016 specifically applied the EPS to SCE's ownership in Four Corners. While recognizing that "D.07-01-039 distinguishes between major refurbishments, such as repowerings, which it identifies as new ownership investment, and much more limited equipment replacements, which it excludes," D.10-10-016 goes on to explain that, in D.07-01-039,
... the Commission was ... "looking for the best and most workable approach to identifying changes in an existing powerplant that would increase the expected level of [greenhouse gas] emissions from the facility over the long-term." Nothing in D.07-01-039 suggests a desire to reduce reliability by requiring the repair of all old parts, rather than replacement. But clearly, the overall objective of establishing the EPS in D.07-01-039 is to focus on ". . . new long-term financial commitments to electrical generating resources that will have major impacts on [greenhouse gas (GHG)] emissions for many years to come. This enables us to prevent major [load serving entity] LSE procurement `backsliding' that will make future GHG reductions more difficult."
(D.10-10-016 at 16, citations omitted.) Accordingly, D.10-10-016 granted SCE an exemption from some of the specific requirements of D.07-01-039 with respect to its Four Corners maintenance expenditures prior to 2012, but held that SCE "should not recover in rates any capital costs planned for Four Corners Units 4 or 5 in 2012 or later, if the related capital projects will increase the life of the powerplant by five years or more" (Id. at 18.)
Now, in this application, SCE requests authorization to spend approximately $1.88 million in 2012 capital expenditures for Four Corners, which represent its 2012 estimated share of specific capital projects necessary for routine operation of the plant and environmental compliance through 2016. Specifically, SCE seeks authority to make expenditures for 12 routine maintenance projects that do not increase the rated capacity of the power plant: One project adds additional ash impoundment capacity; another project will perform a structural repair, and the other ten projects replace like-for-like worn-out equipment. SCE does not seek cost recovery for these expenditures. Instead, upon the close of the transaction, APS will reimburse SCE for these expenditures (minus depreciation) through a corresponding increase to the sale price.
We find it reasonable and consistent with the statutory prohibition on long-term financial commitments and the EPS's overall objectives to authorize SCE to make these expenditures. The overall objective of the EPS is to avoid "long-term commitments to electrical generating resources that will have major impacts on GHG emissions for many years to come." (D.07-01-039 at 35.) As the Commission explained in D.10-10-016 when it granted a limited exemption from D.07-10-039 for pre-2012 capital expenditures for Four Corners:
Accordingly, this Commission has discretion to define ["new ownership investments"] in a way that is consistent with [Senate Bill (SB)] 1368's7 policy objectives, even if that involves defining it somewhat differently than we did in D.07-01-039. Because the exemption we are granting here is limited in scope and duration and because we are requiring SCE to undertake a study on the feasibility of continuing its interest in Four Corners after the end of 2011, we concluded that this exemption should not expose California to avoidable [greenhouse gas] compliance costs or future reliability problems:
(D.10-10-016 at 20.) That same logic applies to the 2012 capital expenditures at issue here: In light of SCE's sale of its interests in Four Corners, these expenditures do not represent SCE's long-term commitment to the power plant or expose California ratepayers to avoidable GHG compliance costs. Therefore, we find it reasonable to exempt these limited capital expenditures from the EPS rules adopted in D.07-10-039.
Sierra Club argues that the 2012 expenditures are prohibited. First, Sierra Club argues that Pub. Util. Code § 8341(b)(1)'s prohibition on "long-term financial commitments," which Section 8340(f) defines to include "new ownership investment," categorically bars any new capital investments in Four Corners. Sierra Club argues that, by concluding that it would be unsound to approve an EPS exemption for capital expenditures made after January 1, 2012 (D.10-10-016, Conclusion of Law 1), the Commission established a presumption that SCE is prohibited from making investments in Four Corners after 2011. We do not find Sierra Club's argument persuasive. As discussed above, the Commission has the discretion to define "new ownership investment" in a way that is consistent with SB 1368's policy objectives. For the reasons discussed above, we find it prudent to deviate from D.10-10-016's restrictions on SCE's expenditures for Four Corners in 20128 and to exempt SCE's limited, routine 2012 capital expenditures from the EPS rules adopted in D.07-10-039.9
Sierra Club asserts that, even if the 2012 expenditures would be permitted so long as they do not increase the power plant's life by five years or more, SCE has not met its burden of proving that to be the case. Although we do not reach this issue because we exempt SCE's limited, routine 2012 capital expenditures from the EPS rules adopted in D.07-10-039, we note that Sierra Club improperly relies on non-record material in support of this assertion. Sierra Club attaches, as "Exhibit 1" to its interim opening brief, the June 1, 2011, prepared testimony of its witness in SCE's 2012 GRC. Sierra Club states that it "seeks to introduce this material" because it is relevant and because the evidentiary record for this issue is not yet closed. (Sierra Club interim opening brief, fn. 4.) This is not grounds for "introducing" the material through legal briefs. The time to introduce evidence is at evidentiary hearing or by motion. We strike Exhibit 1 to Sierra Club's interim opening brief and accord no weight to its discussion referencing that material.10
Sierra Club argues that D.07-01-039 prohibits investments that increase the actual operating capacity of a power plant, regardless of whether the rated capacity remains the same. Sierra Club is incorrect. D.07-01-039 makes clear that prohibited capacity increases are those that change the rated capacity, which is defined as the plant's maximum rated output under specific conditions designated by the manufacturer and usually indicated on a nameplate physically attached to the generator. (D.07-01-039 at 53.) SCE's proposed 2012 capital expenditures will not increase Four Corners' rated nameplate capacity.
4.5. What is the appropriate ratemaking treatment of the gain on sale?
SCE proposes to record the net after-tax gain on sale, grossed up to a revenue requirement level, as a credit to the generation sub-account of SCE's Base Revenue Requirement Balancing Account. After careful scrutiny by TURN, SCE's proposal is uncontested. SCE's proposed ratemaking treatment is reasonable.
4.5.2. Proceeds from termination of transmission rights
In addition to the Sale Agreement, SCE and APS entered into a Transmission Service Termination Agreement (TSTA) pursuant to which APS will pay SCE $40 million for termination of the Edison-Arizona Transmission Agreement (EATA) and the associated transmission rights, and SCE will pay APS $27.8 million to release SCE from any obligation to reimburse APS under the EATA for payments due to the Navajo and the Hopi Tribe for use of rights of way across tribal lands through July 1, 2011. SCE asserts that the TSTA is subject to Federal Energy Regulatory Commission (FERC) approval and that the proceeds from the TSTA are FERC-jurisdictional.
TURN urges the Commission to direct SCE to structure its proposal for FERC approval of the TSTA such that the full net proceeds of the TSTA flow to ratepayers or, in the alternative, to require SCE to inform the Commission as to how it intends to structure its proposal so that we may have a full and complete understanding of all of the elements of this transaction. In its opening brief, SCE objects to TURN's recommendations and maintains simply that its future filing at FERC will propose ratemaking treatment pursuant to applicable FERC law and precedent. Based on our expectation that the ratemaking treatment for the net proceeds of the TSTA will conform to applicable FERC law (and the ratemaking treatment discussed elsewhere in Part 4.5), the value of the Sale Agreement is reasonable.
4.5.3. Liabilities for pension and other post-retirement benefits
The Sale Agreement provides that, at transaction close, there will be a true-up related to SCE's share of liabilities for pension and other post-employment benefits (OPEB) associated with SCE's share of Four Corners employees; if SCE's share of the liabilities is underfunded or overfunded, the amount will be deducted or added, respectively, to the proceeds from the sale price. Based on APS's forecast and assuming an October 1, 2012, closing date, SCE estimates the cost of these liabilities to be approximately $21 million; however, APS will provide final calculations at transaction close, which SCE may review and challenge in good faith pursuant to the terms of the Sale Agreement.
TURN raised concerns that the process of determining the pension and OPEB costs at the time of closing provides no incentive to SCE to critically review APS's forecast, and that determining pension and OPEB liability based on a forecast of financial market performance creates a risk that ratepayers will pay more than necessary. TURN therefore proposes that SCE structure its calculations and payments for pension and OPEB liabilities owed to APS over a five-year period in order to reduce forecast error risk to ratepayers.
While TURN's point as to SCE's financial indifference is well-taken, there is no evidence to suggest that APS's forecast of pension and OPEB liabilities, if prepared pursuant to the terms of the Sale Agreement, will be inherently suspect.11 Pursuant to the terms of the Sale Agreement, APS's forecast at the time of closing will be based on the same accounting principles, policies, and methodology as it has historically used in connection with the calculation of the owners' pension and OPEB liabilities. (See Application 10-11-010, Appendix C, "Four Corners - Sale Agreement," Section 3.3(b).) Those accounting principles, policies and methodology are the same as those used for APS as a whole, and are thus subject to audit and to State of Arizona rate regulation. In the absence of any evidence to the contrary, we have no basis to now conclude that those accounting principles, policies, and methodology are unreasonable. To the extent that APS complies with the terms of the Sale Agreement and uses the accounting principles, policies, and methodology that formed the basis for SCE's previously approved costs, it is appropriate to rely on APS's forecast as a reasonable assessment of SCE's pension and OPEB liabilities at the time of closing.
However, preapproval of SCE's recovery of its share of liability for pension and OPEB costs under the Sale Agreement would provide no incentive to SCE to critically review and, if appropriate, challenge APS's forecast at the time of closing. In order to remedy this problem, we will direct SCE to submit a Tier 3 advice letter for recovery of its pension and OPEB liabilities under the Sale Agreement based on its independent verification that the costs reflected in the closing statement are based on the same accounting principles, policies, and methodology as APS has historically used in connection with the calculation of the owners' pension and OPEB liabilities. The advice letter shall be submitted within five days after its receipt of the final closing statement, and shall be served on the official service list of this application.
We do not adopt TURN's five-year pension and OPEB liabilities payment proposal. While determining pension and OPEB liability based on a forecast of financial market performance creates a risk that ratepayers will contribute more than turns out to be necessary, it is just as likely that ratepayers will contribute less than turns out to be necessary. TURN's proposal would effectively delay the final reconciliation of the transaction for five years without necessarily providing any ratepayer benefit.
TURN's witness Finkelstein asserts that the APS valuation will occur at a time when market value and performance is at a relative low point and that, all else equal, it will produce a higher forecast of ratepayer contribution to the pension and OPEB costs than is likely to occur, because the greater likelihood is that market value and performance will improve in coming years. (Exhibit 4 at 7.) We are not persuaded. There is no evidence that Finkelstein is qualified as a financial market expert, and there is no other evidence in the record to suggest that late 2012 (when the transaction is anticipated to close) will likely be a relative low point for market value and performance.
TURN points out the inconsistency between SCE's advocacy of the reasonableness of a one-time calculation of pension and OPEB obligations here, where ratepayers (but not shareholders) face that risk, and its insistence on balancing account protection from that same risk for its shareholders. In the absence of evidence that the APS valuation is more likely to produce a higher forecast of ratepayer contribution than is likely to occur and in balancing the interest of closing this transaction in a timely manner, we find the Sale Agreement's terms for forecasting and payment of SCE's pension and OPEB liabilities to be reasonable.
4.5.4. Recovery of outside counsel expenses
SCE proposes to allocate the net gain on the sale of Four Corners to SCE ratepayers, after reducing the amount paid by APS by the amount of certain transaction costs. The current forecast of such transaction costs is $1.1 million, of which slightly more than half ($652,000) is for outside counsel expenses. TURN asserts that the Commission should deny SCE's recovery of outside counsel expenses as a transaction cost here, as SCE's approved general rate case (GRC) revenue requirement includes a forecast of outside counsel costs that reflect the type of costs associated with this transaction. We agree, and conclude that the $652,000 should be removed from the transaction costs to be recovered by SCE from the proceeds of the sale.
SCE's GRC forecasts of outside counsel expenses are not made on a project-specific basis. Rather, as SCE explained in response to a data request in its 2012 GRC:
The reasonableness of the current GRC forecast, however, is not dependent on whether the [omitted name of proceeding], or any other specific, existing litigation matter or proceeding, will continue throughout the GRC cycle. Over the course of a successive period of years, various existing matters terminate, only to be replaced by an assortment of new, and often even more challenging matters.
(Exhibit 18.) So, for example, SCE's 2009 GRC forecast of outside counsel expenses included recorded costs from a Southern California Gas antitrust proceeding before the Commission, even though that proceeding was already closed by early 2008 (Exhibit 4 at 4 and Attachment 3), and outside counsel costs related to efforts over the 2002-2006 period to sell the Mohave Steam Generation plant, even though SCE had ceased such efforts by June 2009 (Exhibit 4 at 4-5 and Attachment 3). Even though these matters had terminated, their inclusion in SCE's forecast reflects that new matters would replace them. There is no compelling reason to deem this new and challenging matter of the sale of Four Corners to be outside the scope of SCE's forecasted outside counsel costs and resulting GRC revenue requirement.
SCE argues that allowing SCE to recoup its outside counsel costs from the sale price is consistent with Commission precedent approving the electric utilities' sale of their generation plants during the late 1990s and allowing them to recover their transaction costs, including outside counsel expenses, from the sales prices. (See D.97-09-049 and D.00-04-009 [SCE]; D.97-12-107 and D.99-04-026 [Pacific Gas and Electric Company]; D.99-02-073 and D.99-03-015 [San Diego Gas & Electric Company].) Nothing in these decisions suggests the Commission was establishing a practice it intended to follow for future generation plant sales. Indeed, the decisions do not discuss the issue of whether and how outside counsel expenses should be recovered or give the Commission's rationale for allowing them to be recovered through the sale proceeds. An argument could be made that allowing direct recovery of outside counsel costs related to the utilities' generation divestitures in the 1990s was uniquely reasonable because the electric utilities' GRC forecasts and revenue requirements at the time had not reasonably contemplated the wholesale restructuring of the electric industry and the mandate that the electric utilities immediately divest nearly their entire stock of generation plants. (See Assembly Bill 1890, Stats. 1996, ch. 854.) Here, in any event, there is no evident basis for deeming the sale of Four Corners to be outside of the "various existing matters [that will] terminate, only to be replaced by an assortment of new, and often even more challenging matters" upon which SCE's GRC revenue requirement is based. (See Exhibit 18.)
SCE argues that, because its recorded 2009 and 2010 costs for Accounts 923 and 92812 were greater than its authorized revenues,13 these outside counsel costs are therefore "incremental" to costs being recovered through current rates. SCE argues that it should therefore be entitled to recover these costs pursuant to "general ratemaking princip[les] of comparing recorded costs to those adopted." (SCE interim opening brief at 15.) There is no such general ratemaking principle that allows a utility to recover revenue requirement shortfalls, even while it is permitted to retain revenues in excess of its authorized revenue requirement. To the contrary, the actual standard is:
Any savings the utility can generate between general rate cases belong to the shareholders. In exchange for this opportunity, the shareholders take on the burden of added expenses it may incur during a rate case cycle.
(D.96-12-066, 1996 Cal. PUC LEXIS 1111, *9.)
SCE suggests that, in view of the fact that shareholders are exposed to risk of disallowance and pursuant to Commission policy that "the incidence of risk is the best determinate of how to allocate gains and losses on sale" (see D.06-05-041 at 91), it would have been reasonable for SCE to propose a sharing of the gain on sale between shareholders and ratepayers. SCE argues that, because it opted instead to return the "entire net after-tax gain" to ratepayers, it is entitled to its transaction costs that are directly related to the sale. To the extent that SCE defines the "entire net after-tax gain" as the after-tax sale proceeds less its outside counsel costs, SCE's point is tautological and does not inform our consideration of whether the outside counsel costs associated with the Four Corners sale should be deemed to be covered by SCE's revenue requirement.
SCE takes issue with TURN's suggestion that outside counsel costs should not be treated differently depending on whether the sale was unsuccessful (through GRC revenue, as in the case of the Mohave generation plant) or successful (netting them from the sale price, as SCE proposes here). SCE counters that according different ratemaking treatment for outside counsel costs for a failed sale and a successful sale is appropriate and analogous to how SCE asserts that it treats such costs in the case of cancelled capital projects (deemed to be GRC operations and maintenance costs) and successful capital projects (capitalized and added to rate base).14 We agree with SCE that the ratemaking treatment for outside counsel costs in the case of failed sales or cancelled capital projects does not dictate the appropriate ratemaking treatment for such costs in the case of successful events. The appropriate inquiry is whether the outside counsel costs in question are reasonably presumed to be associated with the "assortment of new, and often even more challenging matters" that take the place of the matters upon which SCE's GRC revenue requirement was based. (See Exhibit 18.)
Lastly, SCE asserts that recording these outside counsel costs for recovery as a net to the sale amount is consistent with Federal Energy Regulatory Commission Uniform System of Accounts (FERC USOA) instructions related to Accounts 421.1 (Gain on Disposition of Property) and 421.2 (Loss on Disposition of Property). As SCE acknowledged, the Commission has long held-and recently revisited and reaffirmed-that the FERC USAO is not controlling as to Commission ratemaking policies. (See D.06-05-041 at 40-43.)
4.6. Are there unavoidable significant environmental impacts of the proposed project?
The Energy Division issued the draft IS/ND on September 27, 2011, and solicited written comments on it. Notice of the draft IS/ND was served on September 29, 2011, and public comment on the draft was taken through November 3, 2011. Energy Division received four written comment letters from SCE, EDF, Sierra Club, and Pless Environmental Consulting. The final IS/ND was completed after notice and opportunity for public comment on the draft IS/ND, and it documents and responds to those comments.
The IS/ND considered three possible scenarios if the sale of SCE interest in Four Corners is approved, and concludes that the sale of SCE's interest in Four Corners under the Sale Agreement will not have any significant adverse environmental impacts. Scenario 1 assumes that Units 1 through 3 will be retired (as APS proposed to the Environmental Protection Agency that it will do), that SCE will replace the power from Units 4 and 5 with natural gas, and that APS will reduce gas purchases somewhat; under this scenario, GHG emissions will be significantly reduced. Scenario 2 assumes that Units 1 through 3 will continue to run after the sale; under this scenario, GHG emissions will be reduced, although to a much more modest level than under Scenario 1. Scenario 3 assumes Units 1 through 3 are not retired and the utilization of Units 4 and 5 is increased; the IS/ND rejected Scenario 3 from further analysis because APS has stated its intention to close Units 1 through 3, because the energy production that would result under this scenario far exceeds the demands of APS's customers, and because it is not realistic to assume increased utilization of Units 4 and 5.
In its opening brief on CEQA issues,15 Sierra Club argues that the IS/ND fails to provide an adequate project description by including multiple scenarios of how Four Corners will operate after the sale, rather than clearly describing a single operational project. Sierra Club is mistaken. The "project" is the sale transaction. The scenarios described in the IS/ND are not project descriptions; rather, they are estimates of the future emissions impact resulting from the project. Sierra Club's objection to the IS/ND's consideration of the several possible and reasonably foreseeable scenarios is without merit, as it would be unreasonable to consider only one possible and reasonably foreseeable scenario to the exclusion of others.
Sierra Club argues that CEQA requires recirculation of the IS/ND because, by adjusting some of the scenarios' underlying assumptions, the final IS/ND revises the project description. As discussed above, Sierra Club mischaracterizes the identification of reasonably foreseeable results of the project as "project descriptions." The adjustments to the estimates of the environmental consequences of the sale are not a change to the project description.
Sierra Club argues that the IS/ND is inadequate for failing to consider the scenario in which all five units of Four Corners will operate at peak capacity after the sale; Sierra Club asserts that consideration of this scenario is mandated because there is nothing to prevent APS from operating Four Corners in this manner. To the contrary, the mere hypothetical possibility is not substantial evidence that this scenario is reasonably foreseeable. Sierra Club made these assertions in its comments on the draft IS/ND, and the IS/ND reflects these comments and provides reasonable explanations for omitting these factors. (Exhibit 19, attached January 24, 2012, Response to Comments Received on the Draft IS/ND, Section 2.4.2 (including but not limited to A-18 through A-25).)
Sierra Club argues that the IS/ND is inadequate for failing to include ongoing plant modifications and SCE's proposed relinquishment of transmission capacity from the project description, and for failing to consider the potential for significant increases in GHG emissions as a result of past and on-going plant modifications. Sierra Club made these assertions in its comments on the draft IS/ND, and the IS/ND reflects these comments and provides reasonable explanations for omitting these factors. (Exhibit 19, attached January 24, 2012, Response to Comments Received on the Draft IS/ND, Sections 2.3.2 and 2.4.2 (including but not limited to A-2, A-6, A-10, A-11, A-12, A-13, A-14 and A-15).)
EDF argues that, because the IS/ND's conclusion that the project will have no significant environmental impacts is sensitive to future utilization rates for Four Corners Units 4 and 5, the Commission should require SCE to monitor and report emissions from Four Corners and undertake mitigation in the event that emissions exceed the significance level. El Dorado Taxpayers for Quality Growth v. County of El Dorado, 122 Cal. App. 4th 1591, 1602 (2004), to which EDF cites in support of its argument, is off-point: In that case, the responsible agency required a monitoring program in order to mitigate an identified potential environmental impact; in this application, the IS/ND does not identify a potential environmental impact that requires mitigation.
EDF argues that the Commission should take the opportunity to achieve the greatest possible reduction in GHG emissions by conditioning the sale on APS's commitment to retire Units 1 through 3, and cites to the Commission's authority, under Pub. Util. Code §§ 701 and 851, to impose conditions on the sale of utility property. EDF's argument goes to the reasonableness of the proposed sale, but it does not put into question the adequacy of the IS/ND and its conclusion that the project will have no significant environmental impacts.
We have reviewed and considered the information contained in the IS/ND, as well as Sierra Club's and EDF's challenges to the adequacy of the IS/ND. We certify that the IS/ND has been completed in compliance with CEQA, that the IS/ND was presented to us and that we have reviewed and considered the information contained in it, and that the IS/ND reflects our independent judgment and analysis.
5 DRA states that it is neutral as to the reasonableness of the value of the Sale Agreement at this time, but argues that the Commission should re-evaluate the reasonableness of the value of the proposed sale based on more current data if it does not resolve this proceeding by March 31, 2012. Since the proposed decision is issued so that the Commission may resolve this proceeding in the first quarter of 2012, we do not reach this issue.
6 See Four Corners Sale Agreement, Section 10.1 (Right to Terminate), Attachment C to Application 10-11-010, granting Purchaser and Seller the right to terminate if, among other things, required regulatory approvals are conditioned in form or substance not reasonably satisfactory to the Purchaser or Seller.
7 Stats. 2006, ch. 598.
8 The Commission is not bound by its own precedent (In re Pacific Gas & Electric Co. (1988) 30 CPUC 2d 189, 223-225).
9 Furthermore, we note that D.10-10-016 only prohibits rate recovery of capital expenditures beginning January 1, 2012 (Ordering Paragraph 2) and that, under the Sale Agreement, the costs of the 2012 capital expenditures will be recovered from the buyer, APS, except to the extent of any depreciation incurred prior to the sale.
10 Similarly, we strike "Exhibit 2" to Sierra Club's interim opening brief, the May 31, 2011, prepared testimony of its witness before the Arizona Corporation Commission, and accord no weight to its discussion referencing that material. (Sierra Club relies on this non-record material to demonstrate that the sale will not have environmental benefits).
We also strike footnotes 1 and 2 to Sierra Club's interim opening brief, which respectively cite to an August 20, 2009, Environmental Protection Agency news release and a June 9, 2005, MSNBC news article, and accord no weight to its discussion referencing the materials. These materials are not in the evidentiary record and are not officially noticeable. (See Rule 13.9.) (Sierra Club relies on these citations to demonstrate the extent and impact of pollution caused by Four Corners.)
11 TURN argues that SCE's testimony in its 2009 general rate case proceeding, wherein SCE challenged TURN's use of APS's budget forecast, proves that it can be inappropriate to rely on APS's forecasts as the best estimate of SCE's expenses. (TURN reply brief at 10, citing to Exhibit 16 (Excerpt from SCE 2009 GRC Rebuttal Testimony, Coal O&M and Capital Expenditures at 2.) However, Exhibit 16 states that APS's long range budget forecast was not the best estimate of SCE's expenses because "APS does not include any allowance for cost increases for possible future regulatory changes, or the increasing operations and maintenance needs of aging plant;" it is not apparent that APS's forecast of pension and OPEB liability would be affected by this forecasting practice.
12 Accounts 923 and 928 are apparently related to operations and maintenance expenses, and presumably are the accounts to which outside counsel expenses are recorded. (See Exhibit 8 at 34-35.)
13 SCE also asserts, based on SCE's response to a TURN data request which SCE attaches as Appendix A to its interim opening brief, that its recorded outside counsel costs were greater than those authorized in SCE's 2009 GRC. We strike Appendix A to SCE's interim opening brief, and accord no weight to its discussion of it at 15. Appendix A has not been offered or received into evidence, certified as being true and correct (see Rule 13.7(e)), or subjected to the due process opportunity for cross-examination by other parties. As SCE states in its interim reply brief where it takes issue with Sierra Club for having attached non-record material to its interim opening brief, "[i]t would be error for the Commission to even consider this [non-record material] as evidence" and "extremely prejudicial" to other parties if the Commission were to consider it. (SCE interim reply brief at 13.) For example, TURN suggests that, had SCE timely offered this material into the evidentiary record, TURN would have had an opportunity to adduce evidence about whether any of the recorded outside counsel costs should not have been recovered through the GRC process or were removed by SCE because they were recovered outside of the GRC process.
14 SCE cites to "SCE's 2012 GRC, SCE-03, Vol. 5, Part 03 & 04, Ch. I-III, at 27-32" for this proposition. (SCE interim reply brief, fn. 14.) This material is not in the record of this proceeding, and it is it is not officially or judicially noticeable.
15 Sierra Club's opening brief on CEQA issues contains citations to testimony, exhibits, and transcripts in Application 10-11-015, which are not in the administrative record of the IS/ND or in the formal record of this proceeding. (Koppe testimony (Sierra Club brief at 6); Exhibit SCE-17, Vol. 6, Part 3C (Sierra Club brief at 6, 17, 25 and 26); transcript of August 11, 2011, hearing (Sierra Club brief at 6, 17, 25 and 26); transcript of November 3, 2011, hearing (Sierra Club opening brief on CEQA issues at 7, 18 and 28).) Those citations are accorded no evidentiary weight.
