5. The Transfer Application: Discussion
Below we review Joint Applicants' explanation for why they and their owners seek this transfer, the evidence Joint Applicants have offered in support of the transfer, and the basis for DRA's opposition. The discussion largely follows the common organizational outline the parties' use in their concurrent briefs.
5.1. Reason for the Transfer
According to the transfer application and witness testimony, Sierra wishes to sell the California Utility to enable its owner, NV Energy, to focus on Nevada operations, which now extend to most of that state. Load growth in Nevada has required NV Energy to invest an average of $1 billion annually over the past five years to maintain reliable service to the nearly 1.2 million customers it now serves there. Because that load growth has been heaviest in areas that do not border Lake Tahoe (where most of the California Utility's 46,000 customers are located), California operations now serve less than 4% of NV Energy's customer base. The sale, if approved, also provides NV Energy the ability to consolidate all of its operations under a single state regulatory agency and respond to a single set of regulatory directives.
The transfer application describes the genesis of the proposed transaction. Sierra commenced a search in early 2008 for suitable, potential bidders and distributed bid information to an initial list of 40 entities. Sierra required any potential bidder to contractually agree to a list of regulatory commitments and to meet the following criteria:
· experience at operating, and the proven capability to operate, a distribution utility;
· the commitment and ability to continue to offer the same, or greater, level of service at comparable rates;
· the commitment and ability to carry out the regulatory initiatives and policies of California law and this Commission;
· a desire to focus primarily on California operations;
· the commitment and ability to maintain a strong local presence in the service territory within the Lake Tahoe area;
· the commitment and ability to retain Sierra's California labor force; a long-term business objective to operate an electric distribution utility; and
· in general, the abilities, qualifications, and characteristics that would best ensure that the Commission would approve the transaction and entrust the purchaser with the responsibility to provide service to Sierra's California customers and to be the employer for Sierra's California employees.18
Sierra received non-binding bids from seven entities and short-listed four of them, based on review of various criteria (price, bid viability, the completeness of the bid, the bidder's financial and operational qualifications, etc.). Following further review of these criteria and others (impact on employees and customers, etc.), Algonquin emerged as the entity with the best "overall fit." 19 In late 2008, Sierra and Algonquin contemplated executing a purchase agreement, but against the backdrop of the continuing, global financial crisis, Algonquin determined to form CalPeco jointly with Emera. Joint Applicants' witness readily admitted that like many other entities, Algonquin's stock price dropped during the fall of 2008 and its access to capital was impaired. The witness testified that Algonquin's board believed that a joint acquisition with Emera would be "prudent" but that the rationale was not based solely on Emera's financial strength.20 The transfer application reports that the financial markets appear to have viewed the formation of CalPeco by Algonquin and Emera positively, based on stock prices and debt ratings following public announcement of their joint enterprise to purchase the California Utility.
The transfer application states that from the standpoint of CalPeco's owners, Algonquin and Emera, the proposed transfer fits with their mutual business objectives to expand ownership and operation of regulated utility assets, with a view to long-term acquisition and, in some instances, opportunities "to develop and implement renewable energy initiatives."21 Further,
[F]or Emera, this transaction opens up a new market, while providing the opportunity to increase value to its jointly-owned energy infrastructure assets with Algonquin. For Algonquin, this transaction represent an important element in the strategic expansion of its utility infrastructure portfolio and the predictable, long-term related returns that the California Utility will contribute to the stability of its earnings year to year.22
DRA has not put forward evidence that challenges Joint Applicants' explanation of the interest of either the sellers or the buyers in the proposed transaction.
5.2. Impact on Service
Joint Applicants represent that the proposed transfer will continue safe and reliable service and will maintain, and in some instances improve, the quality of service customers experience today. Aligned Protestants, who are located in Loyalton, Portola and adjacent portions of the California Utility's service territory and who raised the sole customer challenge to the proposed transfer, now support it. Initially they criticized the reliability of electric service in their remote area, claiming: (1) local generation is insufficient; (2) existing transmission cannot deliver sufficient power from more distant sources; and (3) field staffing (one person) cannot possibly handle the other kinds of equipment and infrastructure failures that occur in this mountainous and largely rural area. Notably, at the PHC Aligned Protestants did not contend that Sierra should be required to continue to serve them, but rather that PSREC should be authorized to serve instead.
Without conceding any of the alleged service problems, Joint Applicants have agreed to investigate partnering with PSREC to improve local reliability in the Loyalton/Portola area. Generally, however, electric power throughout the entire service territory will continue to move into California from Nevada or elsewhere outside California over the same facilities as it does now (the small King's Beach facility provides very limited local generation). The Power Purchase Agreement, Ex. 10 to the transfer application, ensures delivery of CalPeco's full requirements, including 20% from renewable sources eligible for California's Renewable Portfolio Standard (RPS), at rates reflecting Sierra's actual costs and based on Sierra's system-average cost, for an initial term of five years. The Power Purchase Agreement gives CalPeco certain rights to develop and/or procure other renewable sources during the five-year term. It also provides an additional, five-year right to obtain power from Sierra in an amount up to CalPeco's full requirements for nonrenewable sources. Ongoing transmission will be negotiated in accordance with federal law on non-discriminatory, open access transmission and Sierra's Federal Energy Regulatory Commission (FERC) tariffs.
With respect to reliability in the Loyalton/Portola area, Joint Applicants have reached an agreement with PSREC for CalPeco to contract for additional line crew assistance as needed (we discuss this below in Section 5.3.3, as part of the PSREC Settlement). In South Lake Tahoe, they propose to reopen a customer service counter that now is closed. While generally CalPeco expects to hire the same employees who now operate the system for Sierra, Joint Applicants also have disclosed CalPeco's plans to locate corporate headquarters, senior management and a customer service headquarters in the service territory. They suggest these initiatives should benefit service by increasing local accountability. Further, Joint Applicants describe CalPeco's intention to introduce software capabilities that will give customers electronic options for bill receipt, payment, service initiation, and scheduling service calls. They claim this initiative follows on Algonquin's successful efforts to introduce "innovative, state-of-the-art billing systems and customer communication programs designed to cost-effectively enhance customer service" to other, small, regulated water and sewer utilities it owns and operates in four states.23 They predict the CalPeco initiative, similarly, will yield both economic and service quality benefits for many customers who live in remote areas and for others who are not domiciled in the service territory year-round. Likewise, Joint Applicants describe CalPeco's preliminary involvement in the Lake Tahoe Green Energy District, which is working to implement, locally, a number of energy efficiency measures and to pursue other "green" projects. Other participants in this enterprise include the local school district and community college, as well as the City of South Lake Tahoe, the State of California Tahoe Conservancy, and the United States Forest Service.
Joint Applicants also point to the favorable assessment by Local 1245 of the proposed transfer's service quality impacts:
We [Local 1245] also believe that CalPeco's local presence, smaller size, resulting sharper focus, and ability to concentrate on matters of particular importance to California and the Lake Tahoe Basin communities will benefit its customers in terms of the quality of the service.24
DRA disputes the need for any of the service improvements proposed for Portola/Loyalton and elsewhere. DRA's primary contention is that these and other changes necessarily will increase costs for CalPeco. DRA predicts that as a standalone utility with 46,000 customers, CalPeco will lack the economies of scale available to Sierra and that therefore, the transfer will lead to a substantial rate increase request in the next general rate case. Service quality cannot be divorced completely from its cost, and we discuss these cost concerns below. However, nothing in the record suggests that service quality will decline under CalPeco. Rather service quality will continue at present levels generally, and in some respects may improve, given Joint Applicants' stated intentions as well as its responsiveness to registered customer concerns.
5.3. Impact on Costs
Joint Applicants maintain that the transaction has been structured to enable CalPeco, post-closing, to collect from customers the same total revenues that Sierra is authorized to charge and collect, at the same rate levels now applicable to individual customers.25 DRA does not dispute this but argues that cost increases are inevitable, that they will lead to rate increases in the future, and that for these reasons the Commission simply should deny the transfer application.
The "Premium and Cost Synergies" section of the Regulatory Commitments contains three promises that shield customers from costs solely attributable to the proposed transfer from Sierra's ownership: (1) CalPeco will not seek to recover from customers the purchase premium (the excess of the purchase price over recorded, regulatory book values for utility assets); (2) CalPeco will use its actual recorded costs levels, including any cost savings (from installation of electronic systems, etc.), as its basis for rate requests in future general rate cases; and (3) CalPeco will not seek to recover from customers transaction costs (investment banking and legal fees, and perimeter metering costs).
However, DRA warns that if the transfer is approved, CalPeco likely will seek a sizable rate increase when it files its first general rate case in 2012. DRA identifies the following as areas of particular concern: Operations and Maintenance (O&M) and certain, other miscellaneous costs; the Transition Services Agreement between CalPeco and Sierra; the settlement with PSREC; and the uncertainty regarding imports of power from Sierra's coal-fired Valmy Power Plant (Valmy). We examine each of these below. Joint Applicants are correct that this transfer application should not be turned into a general rate case. Nonetheless, it is incumbent upon us to assess the record before us for signs of the kinds of serious cost consequences that necessarily must affect any public interest assessment under § 854(a).
DRA's opening brief also argues, for the first time, that CalPeco should agree to forego filing a general rate case until three years beyond 2012. Joint Applicants object to this so-called, three-year, rate case "stay out." Not only do we lack a record on any alleged benefits and detriments of this proposal vis a vis CalPeco, but a general rate case deferral is at odds with our policy preference for regular, orderly review of utility operations. We denied DRA's request for one-year rate deferrals for PacifiCorp in D.07-05-031 and for CalAm in D.02-12-068. We decline to impose a three-year deferral here.
DRA contends that CalPeco's smaller size will translate into reduced purchasing power, resulting in increased costs, and ultimately, higher rates. Joint Applicants contend that the evidence does not support DRA's position. They point out that over half ($45 to $50 million) of the current $75 to $80 million revenue requirement is attributable to power supply, which will continue to be incurred at the same cost under the Power Purchase Agreement. While they dispute DRA's claim that CalPeco's smaller size means the certain loss of any economies of scale that Sierra has enjoyed, they also argue that such purchasing advantage could only apply to a portion of the O&M and administrative costs that comprise, in the aggregate, about 10% of the total revenue requirement. Over half of these costs can be expected to be quite stable, since CalPeco expects to hire the same employees under similar compensation packages (presently about $4.6 million) and to purchase and operate the same trucks and other vehicles.
On this point Joint Applicants' witness testified:
[A]s [CalPeco looks] at the 2012 GRC . . . sitting here today there is nothing in evidence from our perspective that would lead us to believe that there would be any cost increase arising from administration or operating costs that wouldn't be present if Sierra continued to own [the California Utility].26
Joint Applicants' brief quantifies the theoretical "risk" of the rest of the O&M costs ($3 to $4 million) escalating at 15% and argues that the resulting increase ($450,000 to $600,000), which would raise the total revenue requirement by less than 1 %, could not reasonably be termed rate shock. Joint Applicants hasten to state that they do not anticipate that CalPeco's recorded costs will cause them to ask for 15% rate increase in O&M, however. Their witness testified:
CalPeco expects no such 15% increase. Nonetheless, CalPeco is comfortable that its costs with respect to the O&M costs would be comparable to the costs that Sierra would incur if it retained ownership.27
While a general rate case will be the place to review the reasonableness of actual costs incurred, this record does not suggest cost consequences of a magnitude large enough for us to find that the proposed transfer will harm ratepayers and therefore, is adverse to the public interest. Our assessment should not be construed to support a reasonableness finding or authorize rate recovery in a future general rate case.
DRA also discounts Joint Applicants' suggestion that cost savings will result from new, electronic capabilities for billing and for scheduling service. DRA relies on testimony that Sierra previously determined electronic billing for the California Utility did not make economic sense. But as Joint Applicants explain, CalPeco would be installing a standalone system based on California rates and tariffs, not adapting an existing system, based on Nevada rates and tariffs, for a small group of customers in California. To be sure, neither party has offered any quantification to support its economic claims. Given Algonquin's apparent past success in this area, we are not persuaded by DRA's assertion that the plan has no merit.
DRA contends that other service enhancements (the reopened customer service counter, etc.) will increase costs without providing value. Again, Joint Applicants state they expect such measures to be cost-effective. Regardless, a general rate case is the place to assess whether undertakings of this nature and relative magnitude are reasonable and warrant recovery in rates.
These issues do not compel a finding that the proposed transaction is adverse to the public interest. Again, this assessment should not be construed to support a reasonableness finding or authorize rate recovery in a future general rate case.
Under the Transition Service Agreement, Ex. 12 to the transfer application, CalPeco has the option to ask Sierra to perform at cost for 24 months, with a 12-month extension, any of the services Sierra now provides to the California Utility. DRA faults the agreement and Joint Applicants for not specifying, now, precisely which services CalPeco will request. DRA also speculates that once the agreement expires, CalPeco will likely incur higher costs and will seek to collect those higher costs in rates. The Transition Services Agreement appears to be a prudent, interim arrangement to ensure continued good service to ratepayers, rather than a measure that will cause them harm. A general rate case is the place to assess the reasonableness of projections of future costs. These issues do not compel a finding that the proposed transaction is adverse to the public interest.
Joint Applicants' settlement with PSREC is not before us for approval. We discuss the settlement here because of its implications for future costs. While PSREC and the other Aligned Protestants in the Loyalton/Portola area support the settlement, DRA asserts that it "does not offer any benefit to the CalPeco ratepayers at all" and "has generated $1.4 million in additional incremental costs that would not otherwise exist."28
The PSREC Settlement has two primary components. One concerns development of additional transmission capacity in that portion of the service territory and the other, line crew support for the single lineman based there. The Assigned Commissioner's scoping memo directed Joint Applicants to meet in the Loyalton/Portola area with PSREC and the other Aligned Protestants to discuss the problems alleged "and assess how reasonable concerns might be addressed."29 Again, while Joint Applicants have not conceded that any portion of the California Utility suffers from reliability or service deficiencies, we observe that the executed settlement responds to all of Aligned Protestants' allegations (lack of sufficient transmission, lack of back-up generation, and assignment of a single lineman to the area). Nonetheless, if in a future general rate case Joint Applicants fail to prove the reasonableness of either part of the settlement, neither part will ever have any effect upon rates.
With respect to transmission, the settlement provides for CalPeco and Sierra shareholders to make a capital investment of $250,000 in PSREC`s Herlong Transmission Project. In addition, Sierra will work with PSREC to increase transmission capacity through PSREC's Marble Substation, in order to expand reliability for both by means of additional, backup transmission service. Joint Applicants describe the Herlong Project as follows:
This project is to be structured to connect PSREC's system directly with Sierra's system to provide PSREC greater access to less expensive power from sources east of California. PSREC also intends that this project provide CalPeco's customers greater reliability by the addition of an additional transmission line and also access to additional generation sources north and east of California.30
Under the settlement, if CalPeco determines the Herlong Project has sufficient, independent merit to CalPeco's ratepayers to warrant a further capital investment, and if the Commission subsequently agrees and grants CalPeco authority to make that investment on behalf of ratepayers, CalPeco will commit a total of $1 million to the project. In that case, the settlement provides for the initial $250,000 shareholder payment to be credited against CalPeco's $1 million investment. We have no reason to attempt to weigh here whether the Herlong Project will have value for CalPeco. That issue belongs in a future general rate case.31
The resource support agreement in the PSREC Settlement provides the terms by which CalPeco will obtain additional line crew services in the Loyalton/Portola area (one lineman and a bucket truck, or the equivalent, for a minimum number of hours annually over a ten-year initial term). CalPeco agrees to absorb 100% of the cost of the resource support agreement between the date of closing and the effective date for rates authorized in a 2012 general rate case.
These issues do not compel a finding that the proposed transaction is adverse to the public interest.
As discussed above in Section 5.2, the Power Purchase Agreement provides for five years' continued delivery of CalPeco's full requirements for electric power at Sierra's system-average cost. Currently, Sierra's power supply mix to its California customers includes electricity generated at Sierra's coal-fired Valmy plant, which commenced operations in the early 1980's. The question arises whether CalPeco may contract for five years for a power supply mix that includes Valmy, given California's statutorily-mandated greenhouse gas (GHG) Emissions Performance Standard (EPS). According to DRA, the rate consequences of prohibiting inclusion of Valmy make the proposed transfer uneconomical - the 2012 impact will be an increase in the average residential rate by "9.95% from $0.12405 per kWh to $.13639 per kWh," following close upon a sizeable residential rate increase (7.75%) in Sierra's 2009 general rate case.32 Joint Applicants calculate the rate impact for the more expensive cost supply mix at $7.6 million starting in 2011.33
In accordance with the statutory guidance in Senate Bill (SB) 1368 (Stats. 2006, ch. 598), enacted in September 2006, the Commission opened a rulemaking to develop the EPS and appropriate rules to implement it. D.07-01-039 approves Adopted Interim EPS Rules.34 Central to the issues before us is this definition in SB 1368:
"Long-term financial commitment" means either a new ownership investment in baseload generation or a new or renewed contract with a term of five years or more years, which includes procurement of baseload generation."35
The statute explicitly prohibits the Commission from approving a long-term financial commitment, and any load-serving entity from entering into one, unless the baseload generation supplied under that long-term financial commitment complies with the EPS.36 Under current law, Sierra may continue to supply power to its California customers from the non-EPS compliant, coal-fired Valmy, however, because Sierra has owned Valmy for several decades. Joint Applicants' witness testified that Sierra has no plans, at present, to make what D.07-01-039 has defined as new ownership investments in Valmy (major retrofits, etc., that would prolong Valmy's useful life by five years or more). Hence, as long as Sierra makes no prohibited, new ownership investments, there is no long-term financial commitment in the context of SB 1368. Enter the contractual arrangement with CalPeco, however, and the picture changes somewhat -- does the Power Purchase Agreement represent a prohibited new contract? D.07-01-039 looks at other contracting issues (what constitutes baseload, how to prevent gaming in contracts with unspecified sources for system reliability, etc.) but does not examine the issue the transfer application raises. Nor has the Commission had occasion to consider the question to date.
Joint Applicants, who argue Valmy should remain in the supply mix, urge us to "allow the pre-Closing status quo to continue - maintenance of existing power sources and customer costs."37 They point out that while approving the transfer but excluding Valmy supply from California will affect the costs for California customers (since power from Valmy is produced below Sierra's system average cost), nothing else will change. Sierra will continue to operate the highly-depreciated Valmy at the same capacity for the benefit of Nevada customers and any emissions that migrate into California now will continue to do so. On the other hand, rejecting the transfer will obligate Sierra to continue to serve the California Utility, which also ensures the continued operation of Valmy.
Since D.07-01-039 provides no direct guidance, we turn to the policy goals of SB 1368, which D.07-01-039 summarizes as follows:
An EPS is needed to reduce California's financial risk exposure to the compliance costs associated with future GHG emissions (state and federal) and associated future reliability problems in electricity supplies. Put another way, it is needed to ensure that there is no "backsliding" as California transitions to a statewide GHG emissions cap: If LSEs [load serving entities] enter into long-term commitments with high-GHG emitting baseload plants during this transition, California ratepayers will be exposed to the high cost of retrofits (or potentially the need to purchase expensive offsets) under future emission control regulations. They will also be exposed to potential supply disruptions when these high-emitting facilities are taken off line for retrofits, or retired early, in order to comply with future regulations. A facility-based GHG emissions performance standard protects California ratepayers from these backsliding risks and costs during the transition to a load-based GHG emissions cap.38
Under the facts applicable here, it is difficult to see how prohibiting inclusion of Valmy power in the Power Purchase Agreement's supply mix for a term of five years would further SB 1368's policy goals. Rather, continued import of Valmy power under the Power Purchase Agreement simply preserves the status quo, operationally and economically. Therefore, we find that inclusion of Valmy power under the Power Purchase Agreement for a five-year term is not a covered procurement, within the context of SB 1368 and D.07-01-039, and thus, is not subject to our EPS rules.39 Beyond the contract's five-year term, we should continue to view Valmy under the same rules that would apply were Sierra to continue to serve the California Utility. Thus, Valmy power may be included in the supply provided under any additional power purchase agreement which Sierra and CalPeco may enter upon the expiration of the initial five-year Power Purchase Agreement as long a Sierra makes no new ownership investment in Valmy, as defined by D.07-01-039, and any relevant, subsequent modifications. Our determination interprets D.07-01-039 solely with respect to Valmy and does not modify D.07-01-039.
5.4. Impact on the Financial Condition of the California Utility
In summary, in addition to a public interest finding under § 854(a), Joint Applicants seek authority under § 816, § 818, and § 851 for CalPeco to finance up to 50% of the acquisition price and to encumber utility assets, including accounts receivables, as security for the debt issuance. As stated previously, Algonquin and Emera have committed to fund CalPeco to ensure initial capitalization of at least 50% equity; their respective ownership shares are Algonquin, 50.001%, and Emera, 49.999%. CalPeco will exist as a stand alone financial entity, with its own capital structure, debt, and credit rating.
Joint Applicants represent that they developed the Regulatory Commitments (Appendix 3) to incorporate conditions the Commission has required in prior § 854(a) applications to safeguard the financial condition of the California jurisdictional utility. The Regulatory Commitments, which confirm a high degree of separateness in CalPeco's structural and financial relationship with its owners and their subsidiaries, include these promises:
· The sole purpose of CalPeco's immediate parent, California Pacific Utility Ventures, LLC, will be to own CalPeco;
· CalPeco's assets will be used solely to provide electric distribution services to its customers and to secure any debt it obtains;
· Any financing by Algonquin and Emera of any business activities other than CalPeco will provide the financing parties no recourse to CalPeco's assets;
· Algonquin and Emera will fund all other business activities independently of CalPeco;
· CalPeco will not provide financing to, guarantees for, extend credit to, or pledge any of its assets on behalf of Algonquin, Emera, or any of their subsidiaries;
· Algonquin and Emera commit to ensure that CalPeco has sufficient capital available for necessary capital investments;
· Dividend distributions by CalPeco may be restricted to maintain minimum, required equity levels;
· CalPeco will retain separate books, financial records, employees and assets and these will be based in California.
Joint Applicants and DRA disagree about whether these commitments provide adequate financial security and we discuss their contentions below.
DRA contends that CalPeco's owners must guarantee its needs for capital and debt, that their commitments in this respect are inadequate, and therefore, that the Commission should impose a first priority condition on them as a condition of any transfer.40 DRA also contends that the ring-fencing measures proposed are inadequate, describing them as "two-way" measures designed to protect Algonquin and Emera as much as or more than CalPeco.41 From DRA's perspective, if the Commission approves this transaction without imposing a first priority condition, it should require Joint Applicants to obtain a non-consolidation opinion that demonstrates the adequacy of the ring-fencing measures.
Joint Applicants' briefs generally challenge DRA for focusing too much on the potential for harm to CalPeco should exigent financial circumstances arise. While Joint Applicants' are correct that it is impossible to guarantee, with absolute assurance, the financial security of any entity into the unknowable future, we do not agree that DRA is amiss for seriously considering the impact of exigent circumstances. At a minimum, recent financial history urges caution. However, we do not find it unreasonable that Joint Applicants oppose imposition of a first priority condition. Algonquin and Emera own regulated utilities in Canada and in four other states in this country and argue that, legally and practically, they cannot put CalPeco in first place before those other entities. As Joint Applicants observe, the Commission recognized this reality in D.02-12-068, when it approved the change of control of CalAm but declined to impose a first priority condition. Joint Applicants further contend that their situation is similar to PacifiCorp's acquisition by MidAmerican, where the Commission found an acceptable safety net in MidAmerican's promise to "obtain sufficient cash from its operations, regular infusions of equity capital from [MidAmerican's holding company], and steady increases in short-term debt."42 Joint Applicants point to the Regulatory Commitments for similar promises by Algonquin and Emera.
Regarding equity infusions, Joint Applicants full commitment now states:
Emera and Algonquin will provide sufficient initial equity to fund fifty percent (50%) of the purchase price for CalPeco. CalPeco shall seek to obtain the balance of the required capital necessary for the purchase price through stand-alone debt issued by CalPeco. Algonquin and Emera are prepared to make this initial equity investment and invest any additional equity in CalPeco based on their understanding that the Commission shall grant CalPeco timely recovery in rates (i) for the reasonable expenses it will make or undertake, respectively, to provide electric service; and (ii) for CalPeco to earn a reasonable return of and on CalPeco's investment in rate base. On this basis Emera and Algonquin are committed to ensure that CalPeco maintains sufficient funds to operate and has sufficient capital available for necessary capital investments. CalPeco, Algonquin, and Emera acknowledge that dividends or similar distributions by CalPeco may be restricted as necessary to maintain minimum equity levels that are reasonable in relation to any equity ratio requirements.43
An earlier version did not commit Algonquin and Emera to provide equity beyond the initial capital infusion; the change was made after hearings, at least in part in response to DRA's criticism. DRA's opening brief argues that the amended commitment remains deficient. DRA faults the amended version because it "put[s] the onus on CalPeco to maintain the necessary funding to operate" and also, as DRA reads the commitment, because it means that rate recovery must be assured before any capital infusions are made.44 DRA further contends that the commitment effectively defines capital as additional equity, only, and therefore "is too limiting."45 DRA refers to the Commission's discussion of capital in D.02-01-039, an interim decision in the Commission's 2002 investigation into, among other things, the meaning of the first priority condition in the context of the holding company structures for the major California energy utilities. There, the Commission examined the holding companies' policies in the context of the electricity crisis. Findings 5 and 6 of D.02-01-039 provide:
5. The term "capital," where not otherwise limited or qualified, encompasses all of the following: the money and property with which a company carries on its corporate business; a company's assets, regardless of source, utilized for the conduct of the corporate business and for the purpose of deriving gains and profits; and a company's working capital.
6. The term "capital" is not limited in the first priority condition to mean only "equity capital," infrastructure investment, or any other term that does not include, simply, money or working cash.46
We conclude that DRA overstates its case on this point. While we agree with DRA that the definition of capital should be understood, plainly, to include money or working cash, the following, very broad clause in Regulatory Commitment 1(g) is reasonably read to encompass working capital as well as capital expenditure: "... Emera and Algonquin are committed to ensure that CalPeco maintains sufficient funds to operate and has sufficient capital available for necessary capital investments."
DRA's other interpretations of Regulatory Commitment 1(g) also fail to persuade. Rather, the language reflects two established, general principles: (1) a regulated utility should be self-supporting where possible, and (2) under the decades old regulatory compact, rate recovery can be expected for all reasonable expenditures made in the provision of safe and reliable utility service. We do not think the amended commitment can fairly be read to suggest that Algonquin or Emera plan to abandon CalPeco if an unusual or extreme need for cash should arise. Even before Joint Applicant's revised this commitment to extend it to additional equity infusions, their witness testified:
[I]f there were an extraordinary event - a storm of some profound magnitude that required some kind of capital infusion to protect the asset, then I would assume that CalPeco would either seek to obtain those funds or they'd be forthcoming from the parent to protect the asset.47
In addition, DRA argues that CalPeco's small size may increase its cost of debt. As DRA notes, this claim is frequently heard in ratemaking proceedings at the Commission, though it is not accurate in all instances. DRA has not shown, however, how a parental guarantee will benefit ratepayers by ensuring a lower debt rating for CalPeco, particularly when such a guarantee is at odds with standard ring-fencing measures. While the actual cost of debt cannot be known in advance, Joint Applicants' witness testimony further explains their representation that it should be competitive with NV Energy's debt:
Our discussion with the capital markets and lenders in the capital markets have led us on behalf of CalPeco to conclude that the cost of debt that will be sought by CalPeco will be competitive with the cost of debt which is currently outstanding on behalf of NVE.
....
It is through looking at the ratios - the debt-to-energy ratios, looking at interest coverage ratios - that leads us to conclude that the rating that CalPeco will enjoy will be competitive, if not perhaps better in some respects, than NV Energy who has obviously a much broader business offering.48
A parental debt guarantee also serves to undermine the separateness which ring-fencing establishes. DRA does not discuss this issue. Its ring-fencing concerns focus on what DRA's terms the "two way" rather than "one way" nature of the measures that Joint Applicants propose. According to DRA, while the ring-fencing proposals do protect CalPeco from the bankruptcy of its upstream owners, they unreasonably protect Algonquin and Emera from providing any assistance in the case of CalPeco's financial distress. However, the testimony of DRA's witness suggests that DRA's concern really is that CalPeco's owners provide additional capital if needed - and subject to the definitional clarification discussed above, Joint Applicants have addressed that. Asked what Joint Applicants should do to mitigate problems with their ring-fencing proposal, DRA's witness testified that "... the Commission could order the parent company to infuse money into CalPeco if there's future financial hardship."49
With respect to the comparative adequacy of the ring-fencing measures that Joint Applicants' propose, we observe the measures offer value, though they are structured differently than those that MidAmerican developed in the context of the PacifiCorp acquisition. The PacifiCorp ring-fencing includes provision for an independent director at PacifiCorp; before any amendment can be made to the ring-fencing, the independent director must approve the amendment and there must be rating agency confirmation that the amendment will not result in a credit downgrade.50 In Regulatory Commitment 1(e), Joint Applicants propose that no ring-fencing changes be made without Commission approval, which provides a high degree of oversight and ratepayer protection. Moreover, we retain regulatory jurisdiction to proactively require revisions to the ring-fencing measures, given appropriate notice and opportunity to be heard. On balance then, we find the ring-fencing measures adequate - at least at this time - and need not require Joint Applicants to undertake the additional expense of obtaining a nonconsolidation opinion.
5.4.2. Emera Minimum Hold Condition; Internal
Transfer Approval
Algonquin commits to own at least 50% of CalPeco for at least ten years. Emera makes no such commitment, though according to Ex. 3, the first of several status update letters letter submitted prior to hearing, upon closing Emera now plans to acquire a 9.9% interest in Algonquin in addition to its indirect interest in CalPeco. However, the Emera Minimum Hold Condition, a condition to the closing contained in the Purchase Agreement specifies that "[n]o Final Regulatory Order shall have imposed an affirmative obligation on Emera to continue to own its interest in [CalPeco] for any specific period of time following the Closing Date."51 Joint Applicants represent that Emera's disinclination to be bound to hold its interest in CalPeco for any specific period should not be construed as "any intent to `flip' or otherwise shortly sell" its interest in CalPeco but "is simply a matter of maintaining corporate flexibility."52 In response to DRA's cross-examination at hearing, Joint Applicants' witness testified: "I believe we have the ultimate track record of maintaining and holding our investments. I think we are the poster children for the buy-and-hold strategy for the assets that we ... own." 53 Emera's position on this issue basically reflects a "different philosophy" than Algonquin's, he testified, and would wrongly be construed to mean anything else.54
DRA links its concern about the Emera Minimum Hold Condition to a second proposal, termed the Internal Transfer Approval. As described in the transfer application, the Internal Transfer Approval would permit "either Algonquin or Emera to transfer to the other all or any portion of its ownership interest in CalPeco, and without the need for an additional approval by this Commission."55 In Ex. 3, Joint Applicants clarify that they do not intend that this authority override Algonquin's commitment to retain its investment in CalPeco for at least ten years. Ex. 3 also indicates that Joint Applicants would not object to the conditioning of the Internal Transfer Approval upon a requirement that any decrease in Emera's interest in CalPeco occur concurrently with a proportional increase of Emera's ownership interest in Algonquin. Joint Applicants' witness explained that the companies want the Internal Transfer Approval "for convenience and investment flexibility."56 However much they might like to have it, the Internal Transfer Approval is not a deal breaker. Joint Applicants' witness also testified: "[I]f it would increase the Commission's comfort, we would be comfortable with filing, if necessary, for any of those transfers an 854(a) application for your approval."57
DRA contends that the Internal Transfer Approval is not only a bad idea that effectively would permit Emera to abandon CalPeco, posing risks for ratepayers, but more critically, that it is contrary to law. DRA observes that (1) § 851 and § 854 require Commission approval before any transfer of assets or change of control, and that lacking such approval, a transaction is void, and (2) that any attempt by this Commission to pre-approve such transactions, even if lawful, cannot bind future Commissions.
We agree with DRA that these two requests are inter-related. We do not agree that we should impose a minimum hold condition upon Emera. We desire stability for regulated utilities, but we also recognize that § 851 and § 854 provide legal means for approval of reasonable requests for changes in ownership and control. The record does not establish that the proposed transfer is unreasonable unless we impose a minimum hold condition upon Emera. We are less sanguine about the internal transfer authority sought. Whether or not it is lawful (the briefs do not adequately discuss whether the Commission effectively may pre-approve transactions that otherwise would require the filing and review of § 851 and/or § 854 applications), Joint Applicants have not established the Internal Transfer Approval is free of risk to ratepayers. By filing the transfer application as they did, Joint Applicants clearly reached their own determination that Emera and Algonquin should partner in the way proposed. Should they wish to change the financial arrangement at some time in the future, they must file a new application that explains why the proposed change would not be adverse to the public interest.
5.5. Impact on Quality of Management
DRA favorably acknowledges Emera's more than 130-year history of owning and operating electric utility facilities, including electric distribution and transmission systems. But because Algonquin's own, direct expertise is with electric generation facilities and small water and sewer systems, DRA registers concern that without Emera's long-term involvement, the transfer will result in weakened management. Joint Applicants have made a sufficient showing that CalPeco will have competent, professional management, including a competent initial board of directors, whose credentials are listed in Ex. 23 to the transfer application.
5.6. Impact on Utility Employees
As mentioned above in Section 5.2, Local 1245 submitted a letter in support of the transaction shortly after Joint Applicants filed the transfer application. DRA challenges Local 1245's support (though it did not call a union representative or any other employee at hearing), contending that CalPeco has not proposed to offer affected employees continued employment under precisely the same terms and conditions that Sierra now offers. While the witness testimony is not entirely clear on this point, it suggests that the terms for retirement vesting may change for one or more employees who are not vested at present. Regulatory Commitment 4(c) merely states: "CalPeco will recognize the service and seniority of the former employees of Sierra who accept CalPeco's offer of employment for all non-pension purposes including vacation, sick pay benefits and for non-pension post retirement benefits such as retiree health benefits." It appears Local 1245 has not expressed pension concerns and DRA has not discredited Local 1245's letter of support. We find that Joint Applicants have made a sufficient showing that CalPeco will treat employees fairly.
5.7. Impact on California and Local Communities
Joint Applicants focus on service improvements, local hiring as needed, and an increased local presence under CalPeco, all of which can only yield some benefit to the state and local community. DRA's contends that the likelihood of future rate increases render any change uneconomical. We will carefully consider the reasonableness of any rate increase requests in a future rate case filing, weighing evidence on actual costs and actual benefits in that forum. The record on these issues in the transfer application does not establish ratepayer harm.
5.8. Impact on Commission Jurisdiction
Joint Applicants represent that Sierra not only undertook to fully apprise potential bidders of California's jurisdictional requirements but that CalPeco and its owners accept the Commission's jurisdiction and commit to comply with the Commission's orders and with state law. Witness testimony and the Regulatory Commitments confirm the latter, generally, and DRA does not contest this aspect of the proposed transfer. We agree that Joint Applicants have made a sufficient showing that the transfer will not undermine or interfere with the Commission's jurisdiction regarding access to books and records of its owners or with respect to regulatory policies such as the RPS and the GHG EPS. However, though the issue is raised in the Assigned Commissioner's scoping memo, the record does not fully address the Commission's ability to call officers and employees of CalPeco's jurisdictionally foreign, upstream owners to testify in California regarding matters pertinent to CalPeco. To avoid the possibility of future confusion, any approval of the proposed transaction must be conditioned upon access to such officers and employees as the Commission, itself, may determine to be necessary, consistent with established principles of due process and fundamental fairness.
5.9. Impact on Competition
Joint Applicants contend, and DRA does not contest, that the proposed transaction will have no adverse impact on energy markets in California. As Joint Applicants note, the proposed transaction is not a merger of two existing utilities, which might raise market power concerns. Joint Applicants also report that Algonquin, as the 50.001% owner of CalPeco, and Sierra will make the filings with the Federal Trade Commission required under the federal law know as Hart-Scott-Rodino. The record on this issue shows no ratepayer harm.
5.10. Other Operating Agreements
We discuss above two of the seven Operating Agreements that are integral to the proposed transfer - the Power Purchase Agreement (Section 5.2), including inclusion of supply from Valmy (Section 5.3.4) and the Transition Services Agreement (Section 5.3.2). The remaining five, uncontested agreements comprise the following:
· Emergency Backup Service Agreement (Ex. 11 to the transfer application);
· Interconnection Agreement (Ex. 16 to the transfer application);
· System Coordination Agreement (Ex. 15 to the transfer application);
· Borderline Customer Agreement (Ex. 13 to the transfer application); and
· Distribution Capacity Agreement (Ex. 14 to the transfer application).
The Emergency Backup Service Agreement governs CalPeco's proposed provision to Sierra of capacity and energy from the Kings Beach facility for emergency backup service.
The Interconnection Agreement provides how Sierra and CalPeco propose to ensure continued interconnection and coordinated operations between the California Utility's Commission-jurisdictional facilities and Sierra's transmission assets in California, which are subject to jurisdiction by FERC. In particular, if FERC accepts Sierra's request to file the agreement under Section 205 of the Federal Power Act, Joint Applicants ask the Commission to authorize CalPeco to recover any payments it must make to Sierra under the agreement, subject only to ongoing Commission review of the reasonableness of CalPeco's administration of the agreement.
The System Coordination Agreement provides how CalPeco and Sierra propose to coordinate non FERC-jurisdictional, operational matters related to the integrated nature of the California service territory and Sierra's distribution system in Nevada.
The Borderline Customer Agreement provides how CalPeco and Sierra propose to sell wholesale power in order to permit each utility to serve, in the most cost effective way with existing resources, certain customers located near the California-Nevada border. Under the agreement, each utility will apply to FERC for authority to sell power at the rates set forth in the agreement. Joint Applicants ask the Commission to authorize CalPeco to recover payments to Sierra in rates, subject only to ongoing Commission review of the reasonableness of CalPeco's administration of the agreement. Joint Applicants ask the Commission to authorize CalPeco to account for any revenues it receives from Sierra as an offset against its ECAC purchased power costs.
The Distribution Capacity Agreement governs how CalPeco proposes to make capacity on the California Utility's distribution system available to Sierra so that Sierra can cost-effectively serve certain of its Nevada customers located near the California-Nevada border, recognizing that Sierra currently uses electric distribution facilities within California to receive power from Nevada and then to flow that power back to those customers. Joint Applicants' analysis (see Appendix 4 to today's decision) describes why these distribution facilities of the California Utility are "local distribution" facilities subject to the exclusive jurisdiction of the Commission under FERC's seven-factor test. Joint Applicants ask the Commission to retain jurisdiction over the facilities after the closing and authorize CalPeco to provide distribution to Sierra based on the rates and terms in the agreement.
Each of these Operating Agreements has been drafted to permit CalPeco and Sierra to continue to provide electric power, post-closing, to their respective customers in the same way and at the same price as occurs at present.
5.11. Conclusion
Subject to the conditions specifically identified above and in the related Ordering Paragraphs, the transfer application is not adverse to the public interest and should be approved. Joint Applicants' have established that the transfer will not harm ratepayers; in fact, certain service improvements are likely in the near term, at no cost to ratepayers. To the extent service improvements trigger higher costs that result in a request for an increase in rates in 2012 and beyond, CalPeco is on notice that we will carefully scrutinize its 2012 general rate case showing. As is standard in a general rate case, CalPeco will have the burden of proof to establish the reasonableness of its request.
18 Transfer Application at 16-17. The complete, initial list (Ex. 17 to the transfer application) is an earlier version of the Regulatory Commitments found in Appendix 3 of today's decision.
19 Transfer Application at 15.
20 Tr. at 30.
21 Transfer Application at 18.
22 Transfer Application at 18-19.
23 Transfer Application at 5.
24 Ex. 1, Attachment G, November 30, 2009 letter from Local 1245 to Commissioner Grueneich.
25 Joint Applicants ask the Commission to authorize CalPeco to reclassify certain components of general rates to Energy Cost Adjustment Clause (ECAC) rates. This reallocation request arises because CalPeco, which will own no transmission assets and no generation assets other than the King's Beach facility, will purchase both services under the Power Purchase Agreement. Thus, while total revenues will not change, a greater portion of the total will be attributable to fuel and purchased power. The reallocation will avoid cost-shifting between customers and the aggregate, per kilowatt hour (kWh) charge in each customer's monthly bill will remain the same. DRA has not opposed this reallocation.
26 Tr. at 59.
27 Joint Applicants Opening Brief at 40.
28 Ex. 50 at 11.
29 Scoping Memo and Ruling of Assigned Commissioner, February 25, 2010 at 16.
30 Ex. 1 at 37.
31 Joint Applicants admit that at present there is no transmission path between the Herlong Project and customers in the Loyalton/Portola area and that this "could render the Herlong project to be of potentially limited value" to CalPeco. (Ex. 1 at 39.) For this reason the PSREC Settlement has been structured to commit PSREC to enter into other commercial arrangements that will yield a solution for CalPeco.
32 Ex. 50 at 14.
33 Ex. 1 at 43.
34 Interim Opinion on Phase 1 Issues: Greenhouse Gas Emissions Performance Standard (2007), D.07-01-039; the Adopted Interim EPS Rules are found at Attachment 7.
35 SB 1368, Section 2, codifying Pub. Util. Code § 8340 (subpart (j)).
36 Joint Applicants report that they initially contemplated a three-year term for the Power Purchase Agreement but that discussion with the Commission's Energy Division caused them to expand the period to five years to increase supply and price stability.
37 Joint Applicants' Opening Brief at 56.
38 D.07-01-039 at 3.
39 D.07-01-039 uses the term "covered procurement" to mean the types of generation and financial commitments subject to the EPS, pursuant to SB 1368.
40 The first priority condition is fundamental to the Commission's authorization of the formation of the California holding companies that own and control this state's major energy utilities. See for example, D.88-01-063, 1988 Cal. PUC LEXIS 2 *78 (Southern California Edison Company); D.95-12-018, 1995 Cal. PUC LEXIS 931 *72 (San Diego Gas & Electric Company), D.96-11-017, 1996 Cal. PUC LEXIS 1141 *74; as modified by D.99-04-068, 1999 Cal. PUC LEXIS 242 *151 (Pacific Gas and Electric Company); D.98-03-073, 1998 Cal. PUC LEXIS 1 *260, *290 (Enova [Southern California Gas Company, San Diego Gas & Electric Company merger]). The Commission also imposed a first priority condition on the transfer of control affecting jurisdictional portions of two common carrier pipeline utilities, SFPP, L.P. and Calnev Pipe Line, L.L.C., where the new ownership structure comprised a privately-held, limited liability company and a consortium of investment banks, diversified financial services providers, and private equity funds. See D.07-05-061.
41 Ex. 50 at 8. The Commission discussed ring-fencing in D.07-05-061, as follows:
Ring-fencing is the legal walling off of certain assets or liabilities within a corporation. Conceptually, in the context of a public utility within a holding company structure, ring-fencing includes a number of measures that may be implemented to protect the economic viability of the utility by insulating it from the potentially riskier activities of unregulated affiliates and thereby, ensuring the utility's financial stability and the reliability of its service. (See Beach Andrew N., Gunter J. Elert, Brook C. Hutton, and Miles H. Mitchell. Maryland Commission Staff Analysis of Ring-Fencing Measures For Investor-Owner Electric and Gas Utilities. The National Regulatory Research Institute-Volume 3, December 2005 at 7). A non-consolidation opinion is not a ring-fencing measure per se, but focuses on the effect of ring-fencing. A non-consolidation opinion demonstrates that a utility has enough ring-fencing provisions to protect it from being pulled into a holding company bankruptcy. (D.07-05-061, footnote 22.)
42 D.06-02-033 at 26.
43 Appendix B, Regulatory Commitments, Section 1(g).
44 DRA Opening Brief at 20.
45 DRA Opening Brief at 21.
46 Investigation into Pacific Gas and Electric Company, Southern California Edison Company and San Diego Gas & Electric Company and their respective holding companies, D.02-01-039 (2002)
47 Tr. at 85.
48 Tr. at 91-92.
49 Tr. at 138.
50 See D.06-02-033 at 25 and Appendix D: Adopted Conditions, 11.
The National Regulatory Research Institute publication quoted above in footnote 41 discusses a number of ring-fencing measures designed to protect the financial viability of a utility, including: (1) capital structure requirements, (2) dividend restrictions, (3) unregulated investment restrictions, (4) prohibition on utility asset sales, (5) collateralization requirements, (6) working capital restrictions, (7) prohibitions on inter-company loans, (8) maintenance of stand-alone bonds, and (9) independence of board members. (The National Regulatory Research Institute-Volume 3, December 2005 at 5.)
We observe that statute and our regulatory policies effectively impose several of the enumerated measures (for example, utility sales restrictions and capital structure requirements).
51 Transfer Application, Ex. 8, Article VIII, 8.2(h).
52 Transfer Application at 69.
53 Tr. at 87.
54 Tr. at 87.
55 Transfer Application at 70.
56 Tr. at 33.
57 Tr. at 34.
