STATE OF NEW YORK PUBLIC SERVICE COMMISSION
CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/ Restructuring Pursuant to Opinion No. 96-12.
ADMINISTRATIVE LAW JUDGE WALTER T. MOYNIHANREVENUE REQUIREMENT IMPACTS
APPENDIX B - Settlement Agreement Attachments
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STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's Plans for Electric Rate/Restructuring Pursuant to Opinion No. 96-12.
APPEARANCES: See Appendix A
WALTER T. MOYNIHAN, Administrative Law Judge:
INTRODUCTION AND PROCEDURAL BACKGROUND
In Opinion No. 96-12,(1) the Commission expressed its desire to bring to New York State consumers the benefits of a competitive electricity market, together with economic development, lower electric prices and greater customer choice, while maintaining the safety and reliability of electric service. The Commission ordered five of the State's electric utilities to file certain plans, to help bring about these ends.
In compliance with that order, Rochester Gas and Electric Corporation (RG&E or the company) submitted its plan on October 1, 1996. On October 9, 1996, the Commission instituted the instant case for the purpose of examining RG&E's submission.(2) Under the procedural schedule established by the October 9 Order, the parties were provided a 90-day negotiation period during which they were encouraged to reach a settlement in lieu of litigation. Subsequently, the period for negotiation was extended and a Settlement Agreement (Settlement) was entered on April 8, 1997 among staff, RG&E, Multiple Intervenors (an association of more than 60 commercial and industrial energy users), Joint Supporters, and National Association of Energy Service Companies, Inc. A copy of the Settlement is attached as Appendix B.
Hearings on the Settlement were held from June 3 through June 5, 1997; the record contains 2029 transcript pages and 82 exhibits. In addition, statements in support of the Settlement were received from RG&E, staff, and Multiple Intervenors, and statements in opposition to the Settlement were received from the Department of Law (Attorney General); State Consumer Protection Board (CPB); New York Power Authority (NYPA); Association of Retired Persons (AARP); Public Interest Intervenors (PII), a broad-based umbrella coalition comprising 18 consumer and environmental organizations; Public Utility Law Project of New York, Inc. (PULP), a not-for-profit public interest law firm representing the interest of low-income residential consumers; Retail Council of New York (Retail Council), an association of nearly 5,000 retail enterprises in New York State; Independent Power Producers of New York, Inc. and Enron Capital & Trade Resources (IPPNY/Enron); several independent power marketers, including Wheeled Electric Power Company (WEPCO), New Energy Ventures, Inc. (NEV), and Entek Power Services, Inc. (Entek); EnerScope, a consulting firm representing small to medium sized commercial, industrial, and public authority customers; and pro se intervenors Mr. Charles A. Straka and Mr. Jerome P. Bowe. Finally, post hearing briefs were also submitted by many of the above-mentioned parties.
Through informal comments at the five educational forums, and in letters, telephone calls to the Commission's opinion lines, and comments on the Commission's home page on the World Wide Web, approximately 165 individuals provided comments on the settlement. These individuals included representatives of residential groups, small businesses, local economic development agencies, and weatherization and conservation groups.
While the comments generally supported the Commission's goals for a competitive marketplace, four themes emerged from consumers' concerns: system and service reliability; the impact of competition on low and fixed income consumers; the effect of stranded costs on rates, and the need for education of consumers.
The concerns raised included: system reliability must not be compromised and should not cost the consumers more; rates must be lower and affordable for all customers; low-income and low-usage customers should not have to pay higher rates and customer charges should not be increased because it does not encourage conservation. Some consumers expressed the opinion that residential customers will not see significant decreases.
Other concerns expressed were that: access to competitive rates should be available to all customers; competitors should be allowed to be truly competitive and not restricted in their rate/service offerings; management and stockholders, not customers, should bear the responsibility for stranded costs; consumers should have protections against slamming; mechanisms should be in place to avoid cross-subsidization; and service to customers should not suffer as a result of the company's efforts to reduce their costs and increase their profits. Consumers were mixed in their reaction to the speed of implementation of full retail competition with some wanting it to begin early in 1998 and others wanting a much slower pace to make sure all problems are resolved before full competition. Additionally, some consumers stated that they find all the information about how competition will work in the electric industry very confusing, and expressed a need for more education in order to make choices that will benefit them.
In addition, public statement hearings concerning the Settlement were held on May 28 and 29 in Canandaigua and Rochester, respectively. At the public statement hearings, 17 statements were received; however, nine of them were from parties to the proceeding. The eight remaining statements covered a number of important issues in this case including, among others, the smaller revenue decrease that would be allocated to the residential and small commercial customers compared to the larger decreases proposed for the industrial customers, the increase in the residential and small commercial customers monthly customer charge, which would result in an actual overall increase for roughly 43% of the residential and small commercial customers, the lack of a quantification and sharing of strandable costs, which they believed would have justified further reductions in rates, the slow pace of conversion to retail access--about five years, and the lack of a system to decide who would be afforded retail access first, given that it is being gradually introduced.
Generally, the Settlement is intended to resolve all issues in this proceeding. The Settlement would establish electric rates for a five-year period (July 1, 1997 through June 30, 2002) at levels that are, overall, below their current levels. While rates for all customer classes would be reduced, large industrial and commercial customers would receive the most significant price decreases.
Upon approval by the Commission, the Settlement will effect a major restructuring of RG&E's operations, which will open up the company's service area to increased customer choice. On July 1, 1998, the company will begin the first stage, Energy Only, of its Retail Access Program, which allow customers to choose their own supplier of electric energy. A year later under the Energy and Capacity stage, assuming implementation of a statewide competitive market, customers will begin to choose their own supplier of energy and capacity.
Simultaneously, RG&E will restructure its operations so as to functionally separate its business into generation, distribution, retailing, and overall administrative segments. Certain functions, such as distribution, will remain as regulated monopoly services, but others, such as retail service, will be open to competition. For those customers unable (or perhaps unwilling) to select alternative suppliers of energy and/or capacity, the Settlement provides for continued service by a regulated unit of RG&E.
The Settlement also provides for continuation of a program to assist low-income customers and a service quality program intended to maintain safe and reliable service. Further, the Settlement responds to the Commission's directive(3) to introduce retail access to farm and food processor customers on an expedited basis and resolves two pending cases involving judicial review of Commission decisions as they pertain to RG&E.(4) Finally, except as expressly provided otherwise, the Settlement will supersede the current agreement dated May 10, 1996 (the 1996 Settlement) approved with modifications by the Commission on June 27, 1996.(5)
Objection to the Negotiation Process
Mr. Straka complains that he and most other active parties were excluded from negotiations between December 4, 1996 and March 26, 1997 during which staff and the company held bilateral discussions. RG&E concedes that it had developed a draft document with staff but justifies the exclusion of other parties on the fact that earlier negotiations with all parties were unproductive, and in view of the time constraints it wanted to develop a draft agreement, which was eventually presented to and modified based on other parties' views.
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Ordinarily, Mr. Straka's observations would cast serious doubt on the appropriateness of the Settlement from a procedural point of view because staff's and the company's discussions constitute a caucus, which is prohibited by the Commission's settlement guidelines in the absence of notice and an opportunity for all other parties to attend, or unless all the parties consent.(6) However, the October 9 Order waived these guidelines in the instant case to enhance the parties ability to be creative and communicate freely.(7) Thus, the caucusing between staff and RG&E was not proscribed, and the Commission should not reject or modify the Settlement based on Mr. Straka's procedural arguments.
REVENUE REQUIREMENT IMPACTS
The Settlement calls for rate reductions in each of five years culminating in a $27.2 million (4.1%) decrease in RG&E's net electric revenues in the fifth year as compared with rates in effect on July 1, 1996. The cumulative revenue increase, subject to certain contingencies discussed infra, would be $81.4 million. In addition, RG&E will forgo $23 million of incentive payments due it under the terms of prior rate agreements and $50 million of lost net revenues arising from discounts contained in its flex-rate contracts.
RG&E'S CUMULATIVE REVENUE CHANGES
(Millions of Dollars)
|Effective July 1||Revenue Reduction||Mandated Relief(8)||Sub- Total||Kamine Offset1||Net Change|
|1997||$ 3.5||$ 0.0||$ 3.5||$ 0.0||$ 3.5|
The rates to be established to produce the foregoing revenue reductions will not be modified to reflect changes in revenues or expenses, state and local taxes (other than gross receipts taxes and property taxes) and asset sales during the term of this Settlement except for the following items, which are more fully discussed infra:
a. Kamine /Besico-Allegany L.P. (Kamine) recovery;
b. Variations in the levels of mandated relief;
c. Securitization benefits;
d. Deferrals; and
In addition, except for changes arising from a mandated System Benefits Charge (SBC) and securitization, which will be reflected in rates without any limitations, rates will only be changed if the pre-tax net effect of all other such items would on a projected cumulative basis be greater than $30 million during the term of the Settlement. The amount projected to be greater than $30 million will be recovered by adjusting rates, on the next July 1st, for the remaining term of the Settlement; provided, however, no such rate adjustment will be made in rate years(9) 1 or 2, and an adjustment for the five items listed above will not be for less than $3.5 million or greater than $7.0 million for a single rate year in any of the final three rate years of the Settlement, nor will the cumulative effect of all rate increases exceed $12.1 million per rate year. Any amounts that are not recovered as a consequence of these limitations may be deferred by RG&E for recovery beyond the end of the term of the Settlement, and the timing of such recovery will be determined by the Commission.
Staff observes that RG&E will take on new business risks in addition to the rate reductions and forgone amounts under the Settlement. Specifically, RG&E will be required to absorb all revenue losses from the Retail Access Program, and be at risk for a major portion of increases in costs that are under its control (including the impacts of inflation up to 4% on O&M expenses, capital costs, and fuel, which are discussed infra) and other losses of revenues (including losses in revenues due to rate discounts and changed economic conditions).
Staff concedes that, under certain circumstances and with limitations, RG&E may seek increases in rates primarily for costs of implementing the competitive structure envisioned by the Commission or for costs that are largely outside of the company's control. However, under no imaginable circumstances, staff asserts, can more than one-half of the rate reductions provided by the Settlement be offset by the increases in rates permitted by the Settlement.
Inasmuch as the Settlement allows RG&E to retain a portion of the asset sales, and the benefits, if any, from a reduction in property taxes or in other costs resulting from a sale of assets, staff maintains that the company will have an incentive to divest assets, such as unneeded generation facilities. According to staff, this will benefit customers because an asset sale will reduce the regulated rate base. This reduced value will be taken into account when recovery of RG&E's sunk costs is being considered in the future.
Believing that the Settlement will allow RG&E to keep the benefits of assets sales, AARP asserts that this provision is the most egregious of the Settlement. According to AARP, this provision will give the company an incentive to sell generation plant, which has a depreciated book value below the market value of the assets. AARP would rather impose an approach that nets out sales of below market value plant with above market value plant, and then decide how to share the net stranded costs. If the utility is allowed to keep the profits on sales of plant with below market value, AARP argues, the magnitude of the stranded costs remaining could be greatly enhanced. CPB calls for the immediate return to ratepayer of proceeds from the sale of assets. According to CPB, it would be inappropriate to delay returning the proceeds to ratepayers, who are overburdened.
Staff notes that the Settlement prevents shareholders from reaping large earnings windfalls on the sale of plant. The Settlement (as described in greater detail, infra) provides for a per rate-year cap on the return on equity of 14.5% and further provides for equal sharing of the return on equity in excess of 11.8% on a cumulative basis over the five-year term. Pursuant to the Settlement, the customers' share of any excess earnings will be used to reduce sunk costs.
The Attorney General believes that the five-year term will deprive the Commission of the right to take advantage of unanticipated opportunities that emerge as the benefits of competition become apparent.
PII proposes a "price cap plus" mechanism for RG&E's revenue requirement, which is a combined revenue cap and price cap. Under the price cap plus, PII would set the initial year revenue cap using traditional cost of service regulation and in subsequent years, would adjust the preceding year's revenue cap by three factors: inflation, productivity, and growth. For the growth factor adjustment, PII suggest using changes in an index of square feet of developed space. In addition, PII would include a revenue cap true-up in the price cap plus proposal.
According to PII, under its price cap plus the distribution utility will not lose revenues if sales are lower due to energy efficiency or customer owned generation as it will under the Settlement. Thus, PII believes that its price cap plus will promote energy efficiency technologies and small-scale generation, and minimize long-term costs, which it claims is consistent with the Commission's goal of mitigating adverse environmental consequences.(10)
Multiple Intervenors, staff, and RG&E oppose PII's proposed price cap plus. They note that the Settlement was designed to move away from annual rate reviews, but that PII proposal would continue such rate cases. RG&E and staff also question the computation of the growth index. In addition to the difficulty of collecting the data and computing the index, they contend the exact relationship between changes in the index and distribution services is not clear and would be subject to manipulation.
Even if these problems could be overcome, staff objects to the proposal because the price cap portion of the plan has a counter cyclical effect on the revenue cap portion. According to staff, the growth adjustment factor to the revenue cap would be positive during periods of economic growth and negative during periods of economic decline. Thus, the price cap plus would tend to result in automatic rate increases during recessions. RG&E points out that under the price cap plus proposal it would be required to construct facilities to meet its public service obligations to serve new load, but would not have any ability to recover the costs thereof.
Should its price cap plus proposal be rejected, PII requests that the Settlement be modified to place RG&E under an affirmative obligation to begin developing information and skills to consider the cost effectiveness of deferring distribution system costs through the use of distributed generation and local resources. According to PII, the Settlement should specifically require RG&E to prepare detailed annual forecasts of transmission and distribution capital budget requirements and data to support major additions, expansions, or upgrades; begin a load monitoring program consisting of monitors at a significant sample of the transmission and area substations scheduled for addition, expansion, or upgrade; and evaluate and implement cost-effective technologies and/or services as alternatives to major transmission and distribution additions, expansions, or upgrades.
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PII's price cap plus proposal could lead to increased rates if productivity is not sufficient to offset inflation and in any event would require annual regulatory oversight of the true-up mechanism. In effect, this proposal runs counter to the objectives of the Settlement, which is to rely more on competition and less on regulation. With respect to PII's alternative proposal, the Settlement, as will be discussed below, already requires RG&E to maintain the reliability of the system in the most cost-effective manner. PII's call for the preparation of forecasts, load monitoring programs, and various evaluations appears unduly burdensome. For these reasons, its price cap plus proposal and alternative request should be rejected.
The Settlement will establish RG&E's rates for a five-year period with limited opportunities for change. Instead of seeking Commission approval for increases in rates, RG&E will rely more heavily upon its ability to control costs and grow its business to earn increased profits. This emphasis on managerial control to earn more profit is consistent with the introduction of competition to the electric industry. In addition, the incentive to divest generation assets, discussed above, is consistent with the Commission's directive in Opinion 96-12; the Commission "strongly encourage[s] divestiture, particularly of generation assets . . . [and] . . . incentives for divestiture should be worked out individually for each company."(11) After the term of the Settlement, benefits derived from cost reductions will be captured for the ratepayers. A five-year term is not unreasonable because RG&E needs a sufficient period of certainty to make the necessary long-term commitment of its resources to the competitive restructuring process.
RG&E is involved in litigation pertaining to its power purchase from facilities owned by Kamine. While this litigation is pending, the courts have allowed RG&E to purchase the power from Kamine under the company's SC No. 5 buy-back rate for energy at approximately $.02 per kWh. If Kamine were allowed to charge the full authorized rates under the power purchase agreement, it would be entitled to approximately $.08 per kWh. For 1996, the difference in the two rates translates into approximately $27 million in revenues at full capacity. RG&E's electric rates currently in effect include an allowance of $9.6 million for purchases from Kamine.
RG&E states that it was ordered to enter into the power purchase agreement with Kamine. Consequently, the company claims that it is entitled to every penny it pays for power from Kamine. The company points out that Kamine is continuously seeking relief from the court order and there is certainly the potential that, at any time, Kamine might succeed in obtaining such relief. The Settlement will permit RG&E to offset the $114.6 million of revenue reductions by $33.2 million for the duration of the Settlement, which could be used to cover any costs pertaining to the Kamine project resulting from resolution of the dispute between RG&E and Kamine. Moreover, RG&E will be allowed to recover to the extent the $33.2 million is insufficient for this purpose, $10.6 million in rates each year after June 30, 2002 until all the costs of any settlement of its dispute with Kamine are recovered.
In the event that no settlement is reached with Kamine and RG&E becomes obligated to make actual payments pursuant to a court decision on the dispute with Kamine, the company will be entitled, subject to limitations set forth below, to recover on a current basis in electric rates an additional amount not to exceed seven-eights of the difference between the amount that would be payable to Kamine at the maximum output permitted and any amount attributable to Kamine that was included in the rates that were effective as of July 1, 1996; provided that such amount will be reduced by:
(a) amounts accrued pursuant to the Kamine offset; and
(b) any forthcoming securitization benefits otherwise permitted to be used to mitigate Kamine costs.
Also, if no settlement is reached and RG&E is obligated to make additional Kamine payments, rates will not be adjusted until the $30 million threshold and other limits are satisfied. Kamine costs not recovered will be deferred for recovery in subsequent years.
If the $33.2 million provided for Kamine cost recovery ultimately exceeds actual costs attributable to Kamine, the excess balance remaining as of June 30, 2002 will be applied to offset sunk costs, i.e., electric plant and electric regulatory assets.(12)
According to staff, the Settlement establishes a cost recovery mechanism that provides incentives for a settled Kamine solution, reduces potential rate increases, and is equitable to customers by placing some risk on RG&E. If a settlement is reached in the Kamine dispute, staff explains that RG&E will recover $33.2 million under this Settlement and will be entitled to continue to recover the $10.6 million per year already built into rates until all the Kamine settlement costs are recovered. RG&E's shareholders and ratepayers, staff notes, will be worse off in the event that the plant operates and the contract is strictly enforced. If the contract is enforced, RG&E will not be entitled to recover the $10.6 million after the term of the Settlement, and RG&E will have to raise its rates for an extended period of up to 15 years to recover the costs of the contract. Staff questions the ability of RG&E to raise its rates for that length of time in this evolving competitive environment.
RG&E acknowledges that this recovery mechanism is geared to a settlement of the current litigation involving Kamine, but in the event that the matter is litigated and the company is ordered by a court to pay "contract" rates and/or damages to Kamine, the Settlement provides for an adjustment to the planned rate reductions and deferral of any unrecovered balances. According to the company, these provisions are consistent with the prior commitment of the Commission to allow for full recovery of costs associated with the purported Kamine contract.
RG&E also points out that a principal feature of the 1996 Settlement was the Kamine Cost Adjustment Mechanism (KCAM), which in effect eliminated all fuel cost changes except those pertaining to Kamine. Instead of approving the 1996 Rate Settlement in its entirety, the Commission modified it by eliminating the KCAM. RG&E sought redress in an Article 78 proceeding (Rochester Gas and Electric Corporation v. Public Service Commission (Sup. Ct. Albany Co.; Index No. 6616-96)), which is pending. The company asserts that it is crucial that similar unilateral modification not occur with respect to this Settlement. If the Settlement is approved in its entirety and the appeal process is exhausted, RG&E has agreed to withdraw its pending Article 78 proceeding challenging the Commission's action with respect to the 1996 Settlement.
The Attorney General points out that in RG&E's last rate case the Commission reserved the right to review the prudence of any company payment to Kamine. The Settlement in the instant case will place RG&E at risk for one-eighth of its Kamine payments, which the Attorney General believes is less of an incentive to reach a reasonable result, and thus the customers will be giving up a major benefit. Similarly, the Retail Council claims that RG&E actions with respect to the Kamine contract should be reviewed before the Commission assigns responsibility to the ratepayers.
CPB also opposes the Kamine provision and instead would treat this cost the same as other strandable costs, which it proposes be shared equitably between shareholders and ratepayers as discussed more fully infra.
* * *
The Attorney General correctly observes that the Commission in the last RG&E rate case reserved the rights to review the prudence of any company payment to Kamine. However, the Settlement's strong bias towards a negotiated resolution is consistent with the Commission's directive in Opinion 96-12, which established the ground rules for the instant case. In that opinion, the Commission stated:
Some IPP contracts may be bought out or renegotiated . . . . Interested parties are strongly encouraged to pursue agreements that reduce rates to benefit ratepayers. If parties are unwilling, however, to restructure these contracts voluntarily, we shall pursue policies to mitigate the impact of such contracts on rates.(13)
Even if RG&E ultimately loses its cases against Kamine, the Settlement contains some limits on the immediate rate impacts and holds out the possibility that recovery may be subject to the forces of a competitive market for electricity. The provisions related to the Kamine project follow the Commission's directive in Opinion 96-12, are reasonable, and should be approved.
Mandate Relief Related to SBC
In addition to the cumulative revenue reductions of $103.6 million, the proponents anticipate RG&E will be able to reduce its cumulative revenues by $11.0 million to reflect the expected difference between the SBC RG&E supports in Case 94-E-0952(14) and the existing cost of comparable programs contained in RG&E's bundled rates. In any event, the Settlement permits the company to adjust its rates as required to fully recover the costs of SBC programs. To the extent any SBC change occurs, it will be reflected in an adjustment to take effect on July 1 of the next rate year. Cost increases or decreases not reflected during any particular rate year will be reflected in rates in a future rate year as soon as practicable. Except as otherwise provided in the Settlement, any Demand Side Management (DSM) costs incurred after June 30, 1997 by RG&E will be recovered through the SBC or similar charge, and the company will have no such further obligation pursuant to the 1996 Settlement. In addition, the Settlement carries forward the low income program approved by the Commission in the company's last rate case. The current rates reflect about $7.5 million in annual expenditures for all of these programs.
CPB, PII, and AARP addressed a number of issues involving the SBC. CPB requests that spending levels for the SBC be maintained throughout the term of the Settlement at the 1995 level, which the PII also supports although it expresses support for a statewide rate of 1.5 mills/kWh. Both PII and AARP seek establishment of a statewide fund that would provide life-line rates, universal service programs, etc.
Multiple Intervenors calculates that PII's proposed charge would increase RG&E's revenues $2.5 million, to $10 million annually; Multiple Intervenor's opposes the establishment of a uniform per unit charge because it would undermine RG&E's Large Customer Credit Program, which permits large-usage customers to opt out of DSM programs.
* * *
Given the Commission's February 13, 1997 decision to address SBC issues on a generic basis, and the proponents' subsequent decision to defer entirely to the outcome of that other case on the issue of a proper level of SBC expenditures in RG&E going forward, no recommendation is set forth here on PII's 1.5 mil/kWh proposal.
This Settlement allows the company to adjust its rates annually for costs that are ultimately designated by the Commission for collection through a SBC. The signatories further agreed to actively cooperate to identify and implement savings in such costs, and such savings are assumed in the rate reductions described above. Inasmuch as this provision is consistent with the principle of allowing recovery of mandated costs, it should be approved.
Other Mandates, Catastrophic Events and Competition Implementation Costs
During the term of the Settlement, if the cost impact of any individual mandate or any individual catastrophic event exceeds $2.5 million, RG&E will be entitled to postpone the accounting of the entire amount attributable to such mandate or catastrophic event and recover or pass back such amount as soon as possible thereafter, subject to the $30 million threshold and other limitations discussed above. With the exception of Commission-imposed mandates, this accounting postponement will not apply to generating facilities that are fully exposed to market pricing, pursuant to the Energy and Capacity stage of the company's Retail Access Program, described infra. Also, the $2.5 million threshold will not apply to changes in nuclear decommissioning costs that are the result of mandates.
A mandate is defined as (a) any governmental action, including changes in laws and regulations (including tax laws and regulations) and orders of regulatory and other agencies that result in cost changes, and (b) any changes in accounting required by generally accepted accounting principles. In the event that any such mandate consists of actions in response to an asserted failure by the company to conform to valid legal requirements, the company will have the burden of showing that its conduct, which gave rise to such action, was consistent with the best interests of its customers.
A catastrophic event is one that triggers the designation of part of the company's service territory as a disaster area or as being under a state of emergency. The impact will be calculated only with reference to regulated operations.
Moreover, RG&E will be entitled to recover the entire amount of all competition implementation costs that exceed $2.5 million in aggregate in any rate year, subject to the $30 million threshold and other limitations discussed above. For purposes of this Settlement, competition implementation costs means all incremental expenditures incurred by RG&E after February 28, 1997, in connection with all regulatory proceedings, legislation, regulations, and orders pertaining to the implementation of a competitive market for electric service.
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None of these provisions was opposed. They establish reasonable recovery parameters for costs beyond the company's control or resulting from the introduction of competition. They are reasonable and should be approved.
According to the Settlement, the benefits, if any, of securitization that may become available will be used to increase the amounts of the rate reductions in a manner consistent with the legislation or Commission orders authorizing securitization. For purposes of the Settlement, securitization means Commission-issued rate orders, legislatively authorized or otherwise, that are specifically intended to create added credit quality for utility borrowing, allowing assets or utility costs to be financed at more favorable terms than otherwise available. Securitization does not include general rate orders or financing orders issued in the ordinary course.
* * *
To the extent that securitization legislation is enacted and implemented during the term of the Settlement, this provision requires RG&E to pass through to the ratepayers the related benefits in a manner consistent with legislative or regulatory requirements. It should be approved.
Pursuant to the Settlement, RG&E will be permitted to defer for future recovery increases in Cash Operation and Maintenance (Cash O&M) during any rate year in which inflation exceeding 4.0% as measured by the actual GDP Chain-Weighted Price Deflator. Cash O&M includes non-fuel O&M expenses less amortizations. For purposes of the Settlement, Cash O&M is assumed to be $201 million per year until the implementation of the Energy and Capacity stage of the Retail Access Program, at which time Cash O&M will be assumed to be $176 million per year. These amounts will be reduced by any amounts recovered through the SBC provisions.
For property taxes, the company will be allowed to defer for future recovery or pass back 50% of any increase or decrease to the actual property tax expenditures in the base level, i.e., the expenditure during the 12 months ended February 28, 1997 less taxes related to any assets sold after June 30, 1997. In addition, property taxes pertaining to non-nuclear generating facilities will be gradually deducted from the base level in accordance with the schedule set forth in the Settlement.
The Settlement provides that prudently incurred incremental costs pertaining to the shut-down and decommissioning of all generating facilities will be recovered through the company's distribution access tariff. In the event that the estimates of nuclear decommissioning costs change, RG&E, upon Commission approval, will be permitted to change its distribution access rates to reflect such increase or decrease. Increases in non-nuclear decommissioning and shut-down costs will be subject to the $30 million threshold and other limitations on rate increases and any excess may be deferred.
Finally, RG&E will defer site investigation and remediation costs for electric operations in excess of $2.0 million, annually. Any costs deferred under this paragraph will be net of recoveries of these costs from insurance policies or third parties.
CPB finds most of these provisions reasonable, but believes the allowance for inflation is too generous. It proposes that relief be granted only if inflation exceeds 4% and RG&E's actual return on common equity falls below 9% for the same period.
RG&E opposes CPB's proposal, noting that CPB's proposal is asymmetrical because RG&E would have to bear 100% of the excess inflation risk on the downside (from CPB's proposed earned return of 10.2% to 9%) while obtaining only 25% of the upside benefit above a 10.2% return on equity because of CPB's other sharing mechanisms, which are discussed infra.
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It was generally recognized that by requiring the company to absorb a portion of the unexpected costs of inflation and property taxes RG&E is provided with an incentive to minimize such costs. Thus, the Settlement promotes efficiency. However, the parties also recognized the need to balance the risks associated with these cost items in a fair way, and this led to the agreed treatment.
With respect to the decommissioning cost for both nuclear and non-nuclear plant, these costs could be considered sunk costs since these costs will not be avoidable in the future. Further, the recovery of decommissioning costs in the retail access rates is one way to address the Nuclear Regulatory Commission's (NRC's) concerns about financial assurance of decommissioning and therefore should help RG&E avoid having to make other financing arrangements, which could prove very expensive.
CPB's proposal to grant rate relief if inflation exceeds 4% and the return on equity drops below 9% should be rejected. As discussed in a preceding section, RG&E's electric rates will not change unless the cumulative effect of all deferrals exceeds $30 million and then there are limits on the amount that can be reflected in rates. Inasmuch as the company is not free to recover all the effects of inflation; only that above 4%, and since CPB's proposal is asymmetrical, as more fully discussed, infra, no additional limitation (such as the rate of return proposal by CPB) is warranted.
The signatories agree that RG&E should be entitled to rate relief in certain circumstances. Any signatory to the Settlement has the right to petition the Commission for appropriate remedial action if: return on equity for all remaining regulated operations falls below 8.5% or increases above 14.5%, pre-tax interest coverage falls below 2.5 times, or governmental action occurs that cannot adequately be addressed through the provisions of the Settlement pertaining to mandates. The party seeking review has the burden of demonstrating that continued operation of the Settlement is unjust or unreasonable.
Finally, the signatories also acknowledge that the Commission, pursuant to its statutory responsibility, on its own motion or on request of any party, reserves the authority to act on the level of the company's rates if the Commission determines that unforeseen circumstances have rendered RG&E's rates or return on investment unreasonable, inadequate, or excessive for the provision of safe and adequate service.
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These provisions provide a means for considering deficient return on equity and/or interest coverage so that RG&E's regulated operations can be maintained at an acceptable level of financial performance and the company will be able to raise the capital necessary to provide essential public service. They appear reasonable and should be approved.
Return on Equity
Pursuant to the Settlement, if RG&E achieves a return on common equity for its regulated operations in excess of 11.80% for the entire five-year term, the company will be entitled to retain 50% of the amount in excess of 11.80% as earnings and the remaining 50% will be used to write down accumulated deferrals or sunk costs.
According to RG&E and staff, this provision is needed to balance risks and benefits between investors and customers: investors bear the risk of most cost changes under this Settlement, but are allowed to benefit through this provision if the company is successful in managing its costs. RG&E also explains that customers benefit equally from such efforts in that half the benefits will be used to write down costs that could otherwise be recovered through rates at a later time.
The Attorney General and CPB believe the 11.8% earnings sharing threshold should be lowered. The Attorney General proposes sharing commence at 11.2%, the level established in the 1996 Settlement, contending that during the next two years, the Settlement will neither introduce substantially greater rate decreases nor competition then already anticipated in the 1996 Settlement.
CPB proposes the sharing threshold be decreased to 10.2% based on its 10.0% estimated cost of equity for RG&E, as adjusted to 10.2% to reflect the high end of CPB's calculated range of reasonableness. CPB estimates the cost of equity applying the discounted cash flow method and the capital asset pricing model to a proxy group of electric utilities.
Next, CPB claims that RG&E should not be permitted to retain 50% of the excess for its shareholders and use the remaining 50% to write down accumulated deferrals or sunk costs because CPB believes that the shareholders and not the ratepayers will benefit from the reduced exposure to possible non-recovery of stranded costs. Instead, CPB proposes that 50% of any excess earnings be used to write down stranded costs and the other 50% be split between shareholders and ratepayers. Finally, CPB would calculate the excess earning on a year-by-year basis and not over the entire five-year term as set forth in the Settlement.
According to RG&E, CPB's proposed 10.2% return on equity is too low on its face because it is about 130 basis points below the average allowed returns for electric utilities in the fourth quarter of 1996 and first quarter of 1997 and also because the implied spread over bond yields is too low. On the latter point, the company observes that in the Commission's Generic Financing Proceeding, a 350 basis point risk premium above the utilities bond yields was generally employed and 250 basis points was considered the low-end of the range. Since the recent yield on RG&E's bonds is 8.6%, the company calculates CPB's proposal would afford a premium of only about 160 basis points. RG&E conducted its own study and concludes that its current cost of equity is about 11.95% to 12.20%.
Moreover, RG&E points out that another proposal of CPB, i.e., that RG&E absorb substantial write-offs of strandable cost would weaken its financial position by lowering its equity ratio and increasing its risk, which could lead to a decline in its bond ratings. For example, as more fully discussed in the next section, CPB proposes total rate base disallowances of $415.8 million, which RG&E estimates would reduce its common equity ratio to 36.3% as compared with the 49% equity ratio projected for the company in its last rate case as of June 30, 1997. This reduction, when coupled with the resulting declines in coverage, RG&E believes, would cause its bond ratings to fall lower into the BBB category. In addition, RG&E calculates that CPB's recommendations, if adopted in 1996, would have lowered the company's earnings to $1.16 per share, down from $2.32, and below the current dividend level of $1.80.
Finally, RG&E points out that CPB's proposed sharing of excess earnings 25% to ratepayers, 25% to stockholders and 50% to write down strandable costs, in combination with a year-by-year determination instead of the Settlement's five-year average could result in an asymmetrical earning potential. The company explains that in a good year the excess earnings would be shared with the ratepayers but in bad years the earnings shortfall would be completely absorbed by the stockholders, which, over the term of the Settlement, would likely mean that it would never earn the target return. RG&E states that this is unfair and increases unreasonably the risk of its securities.
Staff observes that CPB's 10.2% return on equity is understated because CPB did not allow for a stayout premium and a business risk adjustment. The stayout premium would compensate RG&E for the risk of fixing the return on equity for an extended period generally without the ability to update it. The business risk adjustment would compensate the company for increases in its business risk. Staff did not quantify the premiums for these items.
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Assuming for arguments sake that CPB's lower return on common equity of 10.2% were correct, the addition of a five-year stayout premium would increase the allowed return to a value close to the Settlement sharing threshold of 11.8%. For example, at the time of this writing, the spread between the June of 1997 treasury bills and the May of 2002 treasury bonds is 1.44%. When added to CPB's 10.2%, the equity return would equal 11.64%. Even though this is less than the 11.8%, it must be kept in mind that the 11.8% is not an allowed return on equity that will be reflected in rates, rather it is an earnings sharing threshold. Consequently, contrary to the Attorney General's and CPB's assertions, the 11.8% sharing threshold is reasonable. Since the 11.8% sharing threshold is reasonable, a complete description of each parties criticisms of the other studies of the cost of equity was not set forth and in fact is not needed.
In addition, CPB's proposal to modify the sharing ratio and recompute it on a year-by-year basis would ignore the transitional nature of the Settlement. Over the five-year term, RG&E will face increasing risk as it experiences more and more competition, but CPB's proposal will not share any of the shortfall related to the increased risk. Thus, the asymmetrical aspects CPB's proposal is likely to create a bias over the five years.
Next, although CPB's proposal to reallocate the sharing ratios of excess earnings is more generous to ratepayers, it should not be accepted because the reallocation would upset the overall quid pro quo balance of the Settlement.
CPB proposes to reduce rates by $163,000 to reflect anticipated reforms in the Workers' Compensation Law. RG&E opposes the adjustment claiming that it will not realize the expected premium reductions because the company is self-insured.
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No Workers' Compensation adjustment should be accepted because any change in the actual expense is but one of many changes expected in the future, which will be reflected in the computation of the return on equity. If the return on equity is in excess of the threshold 11.8%, it will be subject to the sharing provisions contained in the Settlement. There is no reason to isolate this one item for special treatment.
Sunk Costs and Strandable Costs
As noted above, the Settlement defines sunk costs as all investment in electric plant and electric regulatory assets. According to the Settlement, RG&E will be permitted to include in its distribution access tariff all prudently incurred sunk costs as of March 1, 1997. This will allow the company to continue to recover such costs during the term of the Settlement. The signatories will meet prior to July 1, 2001 to discuss future ratemaking treatment of sunk costs, which they agree will afford the company a reasonable opportunity beyond July 1, 2002 to recover all such costs.
At the end of the Settlement term, there may be funds available to offset some of the sunk costs. As discussed supra, these funds could come from earnings in excess of the 11.80% rate of return on equity and from unused funds set aside to match a potential liability for Kamine.
Staff reasons that the delay in evaluating sunk cost provides flexibility to explore alternative approaches, with more certainty, for dealing with this issue. In the future, staff explains, information necessary to estimate the future net worth of RG&E's investments in generation assets (sunk costs) such as energy market prices and RG&E's generation costs will be more visible and relevant. By 2001, staff assumes that regional energy and capacity market prices will have developed, and, at that time, there will be a clearer picture of RG&E's generation costs.
Many of the parties opposed to the Settlement insist that strandable costs be calculated at this time and that further rate reductions be authorized by disallowing a portion of the strandable costs. However, only two parties proffered estimates of the strandable costs. AARP presents a strandable cost estimate ranging from $800 million to $940 million and CPB suggests a range of between $1,200 million and $1,500 million. AARP recommends sharing the strandable costs equally between ratepayers and stockholders, while CPB proposes reducing RG&E's rates by an additional 5% as a mechanism for shareholders to absorb a portion of strandable costs. The company estimates that this would require a $168.8 million reduction in rate base.(17)
AARP advocates the use of an administrative valuation approach to measures strandable generation costs, which is based on the difference between projections of RG&E's revenues for electric generation if generation prices were deregulated and projections of revenues if generation prices continue to be regulated at the current embedded costs. AARP further notes that its approach could accommodate a true-up mechanism that would ensure ratepayers and stockholders pay and recover their fair share of strandable costs and alleviate the need for a precise projection.
Believing the Settlement will pass 100% of strandable costs on to ratepayers, AARP asserts it is unfair from two perspectives. First, AARP notes, it precludes residential ratepayers from any hope of gaining significant rate reductions as a result of the transition to a competitive market. Second, AARP argues that requiring ratepayers to pay off the stranded costs allows RG&E's stockholders to be made whole for uneconomic investments or purchase power contracts. AARP points out that all this is apparently to be done without inquiry into the cause of the strandable investment (e.g., bad investment decision, poor planning, legal obligation) or consideration of the extent that prior ratepayers have already paid down these costs. According to AARP, this approach gives shareholders an unfair "investment without risk" at the expense of ratepayers.
According to CPB, its method essentially estimates the revenue requirement per unit of energy of a transmission and distribution company and subtracts that revenue requirement from the revenues per unit of energy sales to consumers. The difference is then compared with competitive generation capacity costs to determine the extent of strandable costs.
CPB estimates that RG&E's strandable costs range from $1,200 million to $1,500 million under two different scenarios. Scenario A assumes 2% average annual sales growth over a ten-year period and competitive market prices for capacity increasing rapidly from zero in 1997 to $.03 per kWh by the year 2000. Scenario B assumes a 1% average annual sales growth over a ten- year period and competitive market prices for capacity increasing rapidly from zero in 1997 to $.03 per kWh by the year 2003. The present worth calculations are based on a 9% interest rate over a ten-year period. In each scenario, CPB assumes that the ultimate transmission and distribution company retains 50% of costs for each of the following categories: general and common electric plant, customer expense, and administrative and general expenses.
According to CPB, RG&E is at a competitive disadvantage in part due to the high level of strandable costs. Therefore, CPB believes that it is necessary to estimate the level of strandable costs and share them fairly between ratepayers and investors so that rates can be reduced. Moreover, CPB asserts that between 1997 and 2000, some of those uneconomic additional costs must be absorbed by RG&E if this State is to move rapidly toward competitive pricing. According to CPB; its proposed 5% strandable cost-related rate reduction for all consumer classes and all consumption levels within classes would achieve this objective and fairly share these uneconomic costs between consumers and investors.
CPB buttresses its claim that RG&E's rates are too high and need to be reduced with a survey showing consumers are most interested in lower electric prices, a comparison demonstrating RG&E's rates are overall higher than 172 out of 200 investor- owned utilities, a study showing RG&E's uncollectibles have grown 19% between 1989 and 1995, a document by the Small Business Administration reporting a statewide slow-down in recent years in employment growth, and finally a survey showing RG&E's residential rates are among the highest in the country.
Multiple Intervenors claims that AARP and CPB have presented overly inflated strandable cost estimates when compared to Moody's estimate for RG&E of approximately $600 million in 1996. Thus, Multiple Intervenors argues that AARP's and CPB's estimates should not be relied upon.
Staff maintains that both AARP's and CPB's strandable cost estimates and proposals suffer from similar infirmities, including computational flaws, errors, and omissions, but even more important, however, is the fact that both AARP and CPB's estimates exceed the 1995 levels of RG&E's sunk investments in generation and regulatory assets. Thus, staff explains, if either of these estimates were used, ratepayers could end up paying more than RG&E's current investments depending on the allocation of responsibility between ratepayers and stockholders. An example of the errors contained in the studies that staff observed is AARP's reliance upon 1995 data, which does not provide an accurate representation of the costs of the Kamine purchased power contract. The omission of the Kamine contract costs alone, staff suggests, could increase strandable costs by over $101 million, and a double count of regulatory assets would decrease strandable costs by $210 million.
Also, staff criticized AARP's proposal to employ annual true-ups of market price and generation costs because doing so would provide RG&E with a poor incentive for efficiency, mitigation, and reduction of strandable costs. Annual true-ups, staff contends, could lead to subsidies for RG&E's generation and thus give it an advantage over competitive generators. Finally, staff notes, annual true-ups could lead to volatile and unpredictable rates and widespread customer dissatisfaction when customers see market rates fall and distribution rates rise.
RG&E and staff oppose estimating strandable costs at this time. RG&E disagrees with assertions that the Settlement virtually guarantees the company recovery of all strandable costs, pointing out that the Settlement reduces rates over an extended period without specifying how RG&E is to reduce its costs sufficiently to recover incurred costs and earn a fair return even while inflation drives up operating costs. The company asserts that it is at risk for managing its operations within the revenues allowed by the Settlement. Those risks include $151 million in the form of rate reductions, rate discounts, and exposure to competition. In addition, RG&E states there are other increased risks that do not lend themselves to precise quantification such as the risks of cost escalation (inflation) and volatility (particularly fuels costs), Kamine costs risks, unplanned outages, and regulatory lag.
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Studies of RG&E's strandable costs are particularly speculative at present because of the lack of competitive market for electricity, which renders the estimates of market energy price a complete exercise in judgment. In addition, AARP's and CPB's studies are based on different methodologies and contain numerous assumptions. These underlying differences when coupled with errors in data and computations have resulted in strandable cost figures that vary widely and exceed the total net depreciated plant of RG&E. Consequently, they should not be relied upon as a basis for rejecting the Settlement.
On the other hand, the Settlement calls for rate reductions without specifying an estimate of strandable costs and allows for future consideration of such costs when some of the variables, such as the actual market price for electricity, will be known.
Moreover, as will be discussed infra, the Settlement provides incentives for strandable cost mitigation by distinguishing RG&E's generation costs between nuclear and non-nuclear sources, providing RG&E a reasonable opportunity (but not a guarantee) to recover sunk costs (nuclear and non-nuclear) made through February 28, 1997, precluding recovery of non-nuclear capital expenditures made after February 28, 1997 from regulated rates, not providing assurance of recovery of nuclear capital expenditures incurred after February 28, 1997, providing that certain generating costs are subject to the market or to long-term incentive plans, and encouraging RG&E to achieve greater efficiencies or sales growth in order to maintain levels of earnings that are comparable to historical levels.
The net effect is that, except for nuclear power and Kamine purchases, the recovery of the remaining half of RG&E's generation, including power purchases, fossil and hydro generation, will depend upon its ability to compete with outside sources of power. If the competitive prices are lower than RG&E back-out rates, ratepayers who purchase that power will automatically enjoy the benefits of and the stockholders will bear the effects of the exclusion of these stranded costs.
The Settlement comports with the Commission's goal that: "[u]tilities should have a reasonable opportunity to seek recovery of strandable costs consistent with the goals of lowering rates, fostering economic development [and] increasing customer choices . . ."(18) This portion of the Settlement is reasonable and should be adopted.
Conclusion with Respect to Settlement's Revenue Reductions
Many parties claim that the overall revenue reduction should be greater, but only a few quantified the amount of savings they foresee. Most notably, CPB set forth a complete proposal demonstrating the revenue impacts of its proposal, AARP proposed several adjustments including, among others, a large adjustment related to strandable costs, PII proffered its price cap plus mechanism, and the Attorney General suggested several adjustments. The proposed adjustments have been considered and weighed against the provisions of the Settlement. Generally, the conclusion reached is that the Settlement's methods for handing the items raised are reasonable.
In addition, this Settlement comes on the heels of the 1996 Settlement, which grew out of a fully-litigated rate case. In that case, staff and other parties scrutinized the company's financial statement. Thus, the existing rates have not only been recently set, but also have been carefully reviewed, and are a solid foundation upon which to build the Settlement's further reductions.
In view of the recent rate case investigation of RG&E, and failure of the parties in this case to demonstrate that more reductions are necessary, there is a high degree of confidence that the revenue reductions contained in the Settlement are reasonable, and the ultimate revenue allowance for RG&E is reasonable.
Nuclear Generating Facilities
According to the Settlement, all prudently incurred costs of RG&E's nuclear interests, Ginna Station and the company's share of Nine Mile Point 2, will be recovered in retail rates at least through 1999. RG&E further commits to participate in good-faith negotiations with staff and with the other cotenants of Nine Mile Point 2 regarding future rate treatment of this facility. The signatories anticipate that similar treatment will be applied to Ginna Station. The proponents agreed that:
a. any Commission or other State solution must be consistent with NRC requirements;
b. a statewide solution to treatment of nuclear facilities is preferable to individual utility-by-utility solutions and any solution pertaining to RG&E must be consistent with a statewide solution;
c. RG&E's nuclear facilities will be subjected to the cost recovery deferral procedures set forth in the Settlement for Commission-imposed mandates; and
d. no change in the treatment of RG&E's nuclear facilities will be implemented until at least January 1, 2000.
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The Settlement provides that nuclear costs will be recovered through regulated rates at least through the end of 1999, which will give RG&E a reasonable length of time to prepare for a possible change in treatment, and is consistent with past regulatory decisions allowing such recovery. In the meantime, negotiations with the operators of nuclear plants under Commission jurisdiction will commence, which will ultimately resolve the ratemaking treatment of the cost of RG&E's nuclear facilities. Parties did not specifically oppose these provisions, but obviously opposed them inherently in their strandable cost adjustments.
Non-Nuclear Generating Facilities
The Settlement addresses the "fixed" and "variable" portions of RG&E's fossil generating units, hydroelectric generating units, gas turbines, and power purchase contracts (other than Kamine) known as the "To-Go Costs." The variable portion of such costs includes the costs that vary as energy output varies at a generating plant, chiefly the fuel expense. The variable portion of the To-Go Costs will be subject to the market for electricity commencing July 1, 1998 in accordance with the Energy Only stage of the Retail Access Program set forth infra.
The fixed portion of such costs is the remainder of all To-Go Costs not defined as variable. The fixed portion comprises all capital costs incurred after February 28, 1997, O&M expenses, and property, payroll and other taxes. The fixed portion of the To-Go Costs will be recovered in full through the company's distribution access tariff until July 1, 1999 after which its recovery will be subject to competition in accordance with the provisions of the Energy and Capacity stage of the Retail Access Program.
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As customers migrate to retail access, RG&E's non-nuclear energy and capacity costs will be gradually exposed to competition. Consequently, the company will have to recover these costs from the competitive wholesale market to the extent possible. Issues raised with respect to the five-year phase-in and the back-out rates are set forth in the discussion of the Retail Access Program.
Miscellaneous Accounting Provisions
A number of specific instructions are presented in the Settlement that resolve the ratemaking treatment of various items. For example, a schedule of items is included setting forth the amounts that will be deemed to have been amortized during the term of the Settlement; all issues pertaining to the cost of legal services are resolved and all the recommendations contained in the final report issued by Mitchell/Titus and Company in November 1993 in the Statewide Legal Services Study are deemed completed; effective as of January 1, 1997, the Commission's policy statement on accounting and ratemaking for pensions and other post-employment benefits(19) will no longer apply to RG&E and to its accounting policies; and RG&E will be permitted, at its option, to book costs associated with Ginna Station maintenance outages on a levelized basis. Such costs shall be deemed to have been recovered from customers on a levelized basis.
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These provisions eliminate future controversy concerning the future ratemaking treatment of the various items; they were unopposed; they should be approved.
Generally the Settlement provides that the revenue decreases will be allocated to RG&E's service classes based on their responsibility for the generation costs. As a result, the Settlement calls for the revenue decreases to be allocated to the various classes so that the large industrial customers will receive rate reductions of 10% to achieve an average rate of $.056 per kWh; large commercial customers will receive rate reductions of 9% to achieve an average rate of $.068 per kWh; other industrial and commercial customers will receive rate reductions of 8% to achieve an average rate of $.08 per kWh; and residential and small business customers will receive rate reductions averaging 2.5%, with rates per kWh varying depending on usage and classification.
Several specific rate design changes were also set forth, including a proposed annual $1.50 increase in the monthly customer charge for the residential and small business customers, elimination of the difference between the peak and shoulder-peak energy charges as of July 1, 1997 for the large industrial customers, and modification of the energy audit requirement in the flex-rate tariffs. In addition, beginning July 1, 1999 and continuing through June 30, 2002, certain incremental manufacturing load of at least 50 kW will be served at an average rate of $0.059 per kWh.
The Settlement provides that all other changes in revenues will be allocated uniformly within each service classification. The company is also authorized to make rate design changes that are consistent with the principle of reducing rates toward marginal energy costs, and may at any time petition for approval to implement revenue-neutral or de minimis rate design changes.
The Settlement also requires RG&E to retain various programs approved in its last electric rate case including the Large Customer Credit Program, which allows large customers to receive a credit if they elect not to participate in RG&E's DSM program; the Low-Income Program, which assists low-income customers; and the Service Quality Performance Program, which would penalize the company albeit at lower levels, for a deterioration in service quality.
Staff, RG&E, and Multiple Intervenors maintain that the relatively greater reductions for non-residential customers will promote efficiency because these large customers, in many cases, have viable options to self generate or locate energy-consuming operations outside the company's service territory where rates are lower. They also note that retention of these customers on the system helps spread fixed costs and thereby, all other things being equal, reduce customers' bills.
Multiple Intervenors also observes that in 1995 RG&E's residential, commercial, and industrial rates were respectively 34.6%, 32.1%, and 61.5% above corresponding national average rates. For this reason, Multiple Intevenors asserts industrial rates should be subject to proportionately greater reductions.
Staff states that the Settlement should be evaluated in terms of the total financial benefits, which show that the smaller customers are treated fairly. For example, staff claims that the quantifiable benefits of the Settlement will exceed $155 million, including the proposed cumulative revenue reduction of $81.4 million and the company's absorption of roughly $73 million in incentives and lost revenues arising from flex-rate contracts. Staff estimates that the residential class will receive approximately 22% of the cumulative revenue reductions and 37% of the write-offs. Overall, the residential class will obtain 30% of the benefits of the Settlement, which staff notes approaches the class's share of total historic revenues (37%) and equals the residential class's percentage of sales (30%).
With respect to the specific rate design proposals, the proponents point out that the $1.50 monthly increase in the customer charge for small accounts with corresponding decreases in energy rates will more closely align RG&E energy rates with their marginal costs, as will the elimination of the differentials in the SC No. 8 peak and shoulder peak rates. Staff observes that in the company's last rate case, the differentials in rate blocks were calculated to be about 73% to 80% depending on voltage levels, while the difference in the corresponding marginal energy cost was only 6% or 7%. Staff goes on to explain that the existing energy audit requirements in flex-rate tariffs are inconsistent with a competitive marketplace and that a continuation of such mandates could penalize the incumbent supplier.
A number of parties challenge the revenue allocation and rate design proposals contained in the Settlement. With respect to revenue allocation, WEPCO, EnerScope, Retail Council, PII, PULP, AARP, CPB, Mr. Bowe, and Mr. Straka object to the fact that the reductions are bigger for the large industrial customers. Generally, they would rather see more of the decreases allocated to residential and small commercial customers.
For example, CPB states that RG&E's rates levels for all service classifications should be reduced equally because all of the company's rates exceed the national average, that job growth in New York is being driven by small businesses, and that residential customers are having difficulty paying their bills as evidenced by RG&E's rising uncollectible growth rate, which is the second worst among the utilities in New York. AARP proposes that the restructuring should ensure that all customers are able to purchase electricity in adequate quantities to meet basic needs at affordable rates, i.e., rates that do not strain the household budget. Thus, AARP would allocate substantial joint and common costs away from basic service and to non-residential and non-basic service.
Likewise with respect to the rate design, CPB believes that the individual components of rates--customer, demand, and energy charges--should also be reduced equally. For the most part, others, including Mr. Straka, criticize the proposed $1.50 increase in the customer monthly charge for residential and small business customers, point out the basic service charge will increase from $10.00 to $17.50 per month over the term of the Settlement, and that this increase will not be completely offset by the reduction in energy charges for low-usage customers. Thus, they point out approximately 131,500 residential customers, 43% of the class, will experience an increase in their electric bills by the fourth year of the Settlement term. They claim that this increase would have an especially hard impact on the low-income customers. PII, meanwhile, claims that shifting revenues to the customers charge will reduce energy rates and therefore increase sales and accompanying pollution. In addition, PII notes such a shift would also lengthen payback periods for energy efficiency upgrades.
PULP argues that no attempt was made to show that the proposed rates are affordable to low-income customers and therefore they may not be just and reasonable. Furthermore, PULP contends there is no statutory authorization granting the Commission a broad mandate to favor larger industrial customers over other business sectors or the residential class. The proposed rate reductions, PULP asserts, irrationally favors one customer class over another and, because there was no showing of need for the favored class, the proposed rate reductions favoring the large customers are assertedly unlawful.
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Generally, the allocation of revenues and individual rate changes are designed to move RG&E's rates closer to the marginal costs. The company's latest marginal cost study, which was initially submitted in its last rate proceeding and reintroduced in this proceeding, supports the proposed revenue allocations and rate designs(20). In that case, the Commission approved the marginal cost pricing concept; it stated:
As far as the revenue allocation and rate design are concerned, the  Settlement will more closely align rates with marginal costs. This realignment is an important step in preparing RG&E and its customers for the increasing competitive environment facing the industry. On the record, RG&E, staff and Multiple Intervenors generally agreed that, as the company moves to a more competitive environment, the cornerstone of electric rate designs will be to approximate marginal cost in pricing.
Marginal cost-based pricing rests on the sound economic principle that efficient resource allocation is enhanced by pricing goods and services as closely as reasonably achievable to marginal costs. It has been our long-standing policy to price electricity such that consumers pay for the cost their consumption imposes on the utility so that scarce resources are efficiently allocated.(21)
More specifically, the customer charges of $17.50 is justified by the fact that the comparable marginal cost is about $20, while the reductions in energy rates for the small customers will more closely align these rates with their corresponding marginal costs.
Rates for existing and new industrial customers in RG&E's service territory will eventually be less than $.06 per kWh, which moves RG&E's industrial rates closer to the national average price of electricity, of approximately $.05 per kWh, and closer to their marginal costs.
The retention of various programs such as Large Customer Credit Program, Low-Income Program, and the service Quality Performance Program will bring costs close to marginal costs, provide some measure of protection to small customers, and encourage the company to maintain high quality service, respectively.
Inasmuch as the Settlement will move rates toward marginal costs, the Settlement is consistent with the Commission's vision to create "effective competition in the generation and energy services sector [and] reduced prices resulting in improved economic development for the State as a whole . . . ."(22) Consequently, the proposed revenue allocations and rate designs are just and reasonable and should be adopted. Use of the marginal costs to reallocate revenues will cause a shift in responsibility, i.e., larger industrial customers will receive greater decreases than residential and small commercial customers, monthly customer charges will increase for residential and small commercial customers, and the SC No. 8 peak and shoulder peak differential will be eliminated. However, these shifts are necessary to realign rates with costs to encourage fair competition in the provision of electricity. If rates were not realigned, RG&E's rate structure would continue the interclass and intraclass subsidies that would render its energy prices uncompetitive.
RETAIL ACCESS PROGRAM
Under the terms of the Settlement, RG&E will gradually open its electric system to competition such that by July 1, 2002 all retail customers will be allowed to choose their own supplier of energy and capacity. The signatories recognize that RG&E's ability to undertake the program is contingent upon numerous conditions, which are not in the direct control of the company. For example, a functioning statewide energy and capacity market is a crucial factor in the company's ability to fully implement its Retail Access Program. Accordingly, the signatories agree that it may become necessary to modify the program to account for such factors, and they agree further to address such matters in good faith and to cooperate in an effort to propose joint resolutions of any such matters.
A number of parties challenge various aspects of the proposed Retail Access Program, beginning with PULP's claim that the Commission lacks the authority to establish such a program.
Commission's Authority to Permit or Require Retail Access
PULP maintains that the Settlement cannot be accepted, first, because the Commission lacks statutory authority to approve general retail wheeling to all customer classes. According to PULP, Public Service Law 66(12-b)(b) limits the Commission's power to "authorize" retail wheeling or delivery of electricity only to qualifying "industrial and commercial customers." Accordingly, PULP argues that there is no authority under existing law for the broad retail access to all customer classes as provided in the Retail Access Plan. PULP also addresses the conditions that must exist under the statute before wheeling to industrial and commercial customers may be authorized.
Staff and Multiple Intervenors respond that PULP raised this same issue in an Article 78 proceeding challenging Opinion No. 96-12, which was squarely rejected by the Supreme Court:
A specific grant of authority in the Public Service Law, authorizing retail wheeling under specific circumstances, may not be construed to defeat an agency's ability to implement broad remedial powers under other circumstances.(23)
Second, PULP argues that the Commission lacks power to deregulate or lighten statutory requirements applicable to new generation providers. For example, PULP cites PSL 65(5), which states that all electric rates, charges and contracts must be filed, and are subject to modification by the Commission. According to PULP, the law does not give the Commission discretion to determine whether electricity sales to retail customers by new industry entrants will be entirely, or even substantially rate regulated. PULP also cites other similar laws and concludes that the Commission is powerless to alter the fundamental legislative scheme. According to PULP, only comprehensive new litigation will permit the kind of broad retail access envisioned by the signatories to the Settlement.
Multiple Intervenors and staff observe that this argument was also raised and rejected in PULP's Article 78 proceeding:
If and when the PSC lightens regulation of generation to accommodate competition, the justiciable issue will be whether such action rationally advances the Legislature's purpose of bringing customers "just and reasonable" electric service. That is the legislative standard, to be determined in particular cases by PSC expertise, subject to judicial review to guard against arbitrary and capricious decisions.(24)
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Since these issues have already been decided by the Court, PULP's positions do not provide a basis for rejecting the proposed Settlement.
Program Design (Single Retailer)
Generally, the Settlement adopts a single-retailer model, which would allow a Load Serving Entity (LSE)(25) to purchase power on the open market and distribution access from RG&E. The LSE would market the power to customers(26) and would have the responsibility for scheduling deliveries based on load shapes or real-time meter data. For the first three years of the Retail Access Program, RG&E will offer billing services to the LSEs so that they may commence operations without having to wait for development of their own billing systems. An RG&E witness also testified that the company will retain ownership of the meters.
RG&E and staff contend that the single-retailer program supports system reliability because it calls for a high degree of coordination between the distribution company and the LSE; provides for high service quality because a single entity will be responsible for the provision of all retailing functions to end-use customers; promotes the creation of a market that will support competing alternative suppliers who will be allowed to add value to electric service through product bundling; and presents substantial opportunities for product innovation and differentiation because suppliers will avoid not only energy and capacity costs but also some of the costs associated with provision of retailing services by the utility.
With respect to the introduction of metering competition, RG&E cites a number of safety, consumer protection, practical, and business concerns. For example, the company points out that:
(1) Local electric codes tend to ignore meters on the grounds that statewide regulation will ensure their safety, but those statewide regulations may not apply to firms otherwise unregulated.
(2) The current systematic meter exchange and testing program to ensure meter accuracy, together with the resulting regular reports to the Commission, could be defeated by competitive metering.
(3) The company at times requires access to meters to restore service. Since meters are often locked, access to meters owned by other firms may be impeded.
(4) In the case of manually read meters installed by other parties, it is unclear what rights those firms have to enter customer premises to read the meters; roughly 60% of RG&E's electric meters are currently inside buildings.
(5) Under RG&E's Retail Access Program, if an LSE were to cease providing service in the Rochester area, it will be possible to quickly transfer customers to other suppliers; however, this process could become considerably more complicated and expensive if the LSE abandoning the area leaves unfamiliar or unusual meters at customer sites that RG&E's distribution business segment cannot maintain or read. At best, RG&E concludes, the need to switch meters will make customer transfers more difficult for the LSE and more of an annoyance to the customer; at worst, an uncooperative LSE, which delayed or refused to remove the old meter, could seriously inhibit competition.
WEPCO opposes the single-retailer model because it fears such a model will impose large, unwarranted costs on ESCOs(27) and preclude all but the largest ESCOs from entering the market. The ESCOs would be responsible, WEPCO explains, not only for the generation they supply but also payment for the delivery service that RG&E provides. WEPCO is also concerned that RG&E may require a large security deposit to ensure payment. WEPCO calls for a rejection of the single-retailer approach and the adoption of a three billing system (one for energy, one for transmission and distribution, and one for retail services), along with the authorization necessary for ESCOs to perform functions related solely to the provision of retail service.
Similarly, Retail Council and IPPNY/Enron criticize the Settlement because it does not provide for the complete unbundling of metering, billing, and information systems (MBIS). The Retail Council believes that competition in this area will lead to innovations in billing, customer classification, and aggregation. Competition in MBIS, the Retail Council and IPPNY/Enron state, has been demonstrated as practical in the near term, and unbundling is achievable and the development of information exchange protocols required to effect such competition will be an evolving process, which could and should start now. They believe that the meter itself is a critical element in the ability to provide value-added service.
Staff responds that WEPCO's concerns about a large security deposit are unfounded, and that the issue of the appropriateness of a security deposit, if one is determined necessary will be the subject of the Operating Agreement, which has not yet been finalized. It is expected to be filed on December 1, 1997 and must be approved by the Commission.
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The single-retailer model makes it convenient for the LSE to create value-added service opportunities, such as product bundling. Consequently, LSE will have the opportunity to calculate the revenues produced by their total relationship with a customer and compare those to the costs of all the services provided. The wholesale cost of electricity will be only one component of those costs.
WEPCO's concerns about the security deposits need not be addressed here because, as staff notes, this will be the subject of the Operating Agreement, which will be filed on December 1, 1997 and requires Commission approval before implementation.
With respect to the unbundling of retail service and the ownership of meters, the Settlement limits the opportunity for competition in this area, which limits the LSE's opportunity to install more sophisticated meters than those owned by RG&E. However, RG&E has raised a number of important concerns that must be resolved before ownership of the meters is opened to competition. Consequently, the Settlement should not be rejected or modified because of this one element. Rather, when weighed in terms of the overall Settlement, it, along with the single-retailer mode, should be accepted as part of the quid pro quo nature of compromise. However, it is recommended that RG&E present a plan to open all of the metering, billing and information systems to competition at the end of the term of the Settlement.
According to the Settlement, the Retail Access Program will be deployed in stages. In the Energy Only stage, which will commence on July 1, 1998, customers will be able to choose their own supplier of electric energy. During this stage, the company will continue to provide and be compensated for the generating capacity required to serve all customers reliably. On July 1, 1999, the Energy and Capacity stage will be introduced, which will permit customers to choose their own supplier of energy and capacity. A schedule of steps that must be taken before either stage can be implemented was set forth in the Settlement.
The schedule for the introduction of competition is as follows:
July 1, 1998 - The Energy Only stage begins at which time customers using up to 670 gWh per year in the aggregate, (approximately 10% of the total load) will be eligible to participate;
July 1, 1999 - The Energy and Capacity stage commences at which time customers using up to 1,300 gWh per year (approximately 20% of total load) will be eligible to participate;
July 1, 2000 - Customers using up to 2,000 gWh per year (approximately 30% of total load) will be eligible to participate;
July 1, 2001 - Customers using up to 3,000 gWh per year (approximately 46% of total load) will be eligible to participate;
July 1, 2002 - All retail customers will be eligible to participate.
To the extent that energy consumption by end-use customers grows beyond a level of 6,714 gWh, the energy caps on eligibility listed above will be increased by the amount of additional energy consumption. Also, in the event that subsequent Commission action places nuclear generation on the market or, if the market price of energy, capacity and retailing exceeds $.032 per kWh, a larger percentage of the customers will be permitted to access competitive generation.
Customers who participate in the Retail Access Program will be permitted to return to RG&E. However, RG&E may establish reasonable measures, including, among others, time and frequency limits on switching, to prevent customers from "gaming" the program. During the Energy Only stage, RG&E will allow such returning customers to take service at regulated retail rates. During the Energy and Capacity stage, the company may charge such customers the equivalent of regulated retail rates plus any additional incremental costs of procuring energy and capacity for such customers. Most new customers will pay the same rates and be allowed to take the same services as returning customers.
Staff and RG&E contend that the Settlement's phase-in of retail access gives customers, communities, and the company an opportunity to adjust gradually to a more competitive market. RG&E notes that an immediate cessation of all bundled service offerings, which would force all customers to choose between competing suppliers, would likely engender stiff resistance from customers who are comfortable with their existing service. Likewise, staff expects that many customers will initially opt to stay with the regulated LSE until they know more about the actual experiences of others in choosing an alternative provider of electricity. Also staff points out that a large amount of load is currently subject to flex-rate contracts and would not be immediately eligible for retail access. Thus, more smaller firm service customers will be allowed to participate initially in the Retail Access Program.
Several other practical reasons were given in support of the phased introduction of retail access. First, the retirement of company-owned generating facilities would deal a serious financial blow to a number of communities, both in terms of lost property tax revenues and reduced employment. An orderly phase-in of retail access would avoid this "overnight" loss of property tax revenues and jobs. Under the Settlement, the retirement or sale of uncompetitive plants will occur over a period that should be sufficient to enable municipalities to adjust to these changes.
Staff also recognizes that the statewide energy and capacity market is not expected to be fully operational any earlier than July 1, 1998. Consequently, staff deems as reasonable a phase-in of Energy Only first to ensure the operation of the statewide market is established for a period of time before RG&E introduces capacity into the retail access program. A 10% first step of a phase-in, staff reasons, will provide a controlled and workable environment in which to prepare for the remaining phases of retail access.
Some parties also note the existence of load pockets on the RG&E system and, as AARP observes, may be a serious problem for RG&E service territory whether or not RG&E continues to own all existing generating units. During 51% of the summer period, the entire territory is in a load pocket situation, i.e., load exceeds the ability of the transmission systems to import power. The percentage drops to 12% in the winter period. In addition, there is a smaller load pocket generally around the City of Rochester 22% of the time in the summer period only.
Staff observes that the Settlement addresses the issue of load pockets. Pursuant to the Settlement, RG&E will be required to maintain the reliability of its system, including those portions of the system identified as load pockets, in the most cost-effective manner, considering a range of alternatives including but not limited to: transmission and distribution system reinforcements, maintenance of existing plant, energy efficiency programs, and distributed generation. Also, the proponents note that RG&E will file a market power mitigation plan with FERC and is required to take appropriate action in accordance with the outcome of that filing.
Finally, responding to some of the parties who oppose the pace of retail access but have generally commented favorably on the level of the contestable rate and the placement of RG&E's non-nuclear generation at risk in the market, staff states that these two elements of the Settlement have been achieved, in part, by agreeing to the five year phase-in of retail access.
In addition, staff points out that a more rapid introduction of retail access may not correlate with a greater number of customers choosing an alternative supplier as was the experience in the telephone industry. Staff also expects that, because a large portion of RG&E's load is currently served under fixed-rate contracts, as alluded to above, the percentage of remaining load that is able to shift to an alternate supplier is much higher than indicated in the Energy Only and Energy and Capacity stages.
WEPCO, IPPNY/Enron, NEV, and Entek would accelerate, in various ways, the schedule for introduction of full retail access. They believe that experience gained with other utilities shows that a more rapid opening of the market is feasible. For example, NEV and Entek suggest that retail access be available to 25% of RG&E load by January 1, 1998 and 100% of its load a year later; WEPCO would eliminate the Energy Only stage and open up 10% of the market by January 1, 1998;; and IPPNY/Enron recommends initiation of complete competition in the provision of all MBIS by that date.
RG&E asserts that it could not meet these aggressive schedules; that it is a small utility with relatively few people with the knowledge and skills necessary for program development. Furthermore, it notes that the Settlement calls for development of the Retail Access Program in one-third to one-half the time originally envisioned by it for the work.
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The Retail Access Program described in the Settlement calls for voluntary participation by customers, and allows customers from every class to participate. Thus, individual customers will control their own migration to the competitive market. Furthermore, customers will be allowed to return to the regulated LSE. Thus, they will be afforded additional protections in the transition period. In addition, as set forth above, the phasing-in of the program will give the customers, communities and RG&E time to adjust to the changing market place.
The two greatest barriers to rapid implementation of retail access are: (1) RG&E's reliance on nuclear generation for about half of its power, and (2) the existence of load pockets in RG&E's service territory for much of the year. The Settlement addresses both problems. The nuclear generation issues will await a statewide solution; as far as the load pockets is concerned, RG&E will be required to maintain its system in the most cost-effective manner and the company will file a market power mitigation plan with FERC and will take appropriate action in accordance with the outcome of that filing. The Settlement also reserves the right of the Commission to implement market power mitigation measures for retail service after the term of Settlement.
Inasmuch as each of these barriers will exist for the near future, the introduction of retail access must be approached cautiously. The Settlement introduces retail access over a five-year period with the biggest step taken in the last year. In sum, the pace for introducing competition should afford RG&E sufficient time to solve the nuclear generation and load pocket programs.
The Settlement includes rates for delivery during both stages of the Retail Access Program, and for deliveries to SC No. 10 flex-rate customers. During the Energy Only stage, the rate for distribution access will equal the average rate for bundled retail service less the per-unit retailing cost and the per-unit energy-related cost of all non-nuclear energy sources, or approximately $.013 per kWh.
In the Energy and Capacity stage, the rates charged to LSEs will be approximately equal, on average, to the rates for bundled retail service less $.032 per kWh, which is the retailing cost and the per-unit fixed and variable To-Go Costs of non-nuclear energy sources, exclusive of property taxes. Twenty percent of the property tax component of the per-unit non-nuclear To-Go Costs will be deducted from bundled rates upon commencement of the Energy and Capacity stage and an additional 20% commencing every 12 months thereafter during the term of the Settlement. The actual distribution access rates will be filed with the Commission as tariff changes.
When the Retail Access Program is opened to all retail customers on July 1, 2002, the company will be authorized to modify its distribution access rates, so as to hold constant the degree to which its To-Go Costs are at risk for recovery through the market. The signatories agree to meet before July 1, 2001 to discuss the future of these ratemaking plans.
Large customers whose SC No. 10 flex-rate contracts expire during the term of the Settlement will have the option to extend their contracts to June 30, 2002, the end of the term of the Settlement, or to obtain a prorated discount on their distribution service if the customer chooses to take service from a LSE or acts as its own LSE. Essentially, the proration will allocate the existing discount between the generation and retailing portion of the customer's bundled rate and the balance.
Staff states that the combination of the single- retailer model with the contestable rate of $.032 per kWh contained in the Settlement should foster a robust competitive market for power in the RG&E service territory. Staff and the company claim that the Settlement's stable and predictable distribution rate, will enable potential competitors to determine one of the most significant inputs of their prices--the cost of distribution service. This, in turn, they maintain, should facilitate the introduction of competition in the service territory as potential competitors, once in possession of this information, will be able to market more effectively.
WEPCO would initiate retail access with the $.032 per kWh back-out rate, thereby eliminating the Energy Only phase. Also, WEPCO suggests that the back-out rate is too low because Pennsylvania adopted back-out rates that are greater. In addition, WEPCO urges that the $.032 per kWh back-out rate be updated periodically to ensure that it reflects current market conditions. Otherwise, WEPCO notes, ESCO's may have to absorb losses if the market price of power rises to levels above the back-out allowance. In such circumstances, WEPCO observes, the fixed back-out rate would discourage competition.
Similarly, IPPNY/Enron criticize the use of an annual average cost of power when the value and marginal cost of that power changes on a continuous basis. They believe the $.032 per kWh back-out price will be less than the market clearing price during peak hours. AARP and IPPNY/Enron also question the usefulness of employing the average cost $.032 per kWh.
AARP suggests a cost of $.015 to $.020 per kWh for retailing functions for small customers based on a rate adopted in New Hampshire. AARP believes the Settlement's allowance of $.004 per kWh for these costs is so low that it will discourage competition. RG&E responds that AARP's retailing costs are based on general considerations rather than specific knowledge of the company's retailing costs.
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Inasmuch as the average $.032 per kWh back-out rate is based on RG&E costs, it should be employed. While some parties have compared this rate with those in other jurisdictions, they have not shown that RG&E's rate understates the company's non-nuclear To Go Costs and average retailing costs. However, AARP raises a valid point when it notes that the retailing costs for residential customers is greater than the average allowance of $.004 per kWh. Even the company concedes the residential retailing cost may exceed the $.004 per kWh allowance.(28) Although this might appear to discourage LSEs from offering service, it should be noted that RG&E is bound to provide billing services for the first three years of the program. Thus, LSEs could purchase the service from RG&E at a below market cost and thereby gain a slight advantage. However, in the last two years of the Settlement, RG&E would no longer be bound to provide unbundled retail services. The advantage, if any, could disappear. The LSEs could then incur the actual cost of retail services, and presumably pass them along to their customers, which could raise the combined cost of power, retailing costs, and access fee higher than RG&E's bundled tariff rate. Instead of a stable competitive environment, LSEs could be whipsawed from a profitable to an unprofitable position at the end of the first three-year of the Settlement.
This scenario can be avoided if the retailing cost, especially for residential and small commercial customers, is accurately estimated and reflected in the backout rate. Inasmuch as the $.032 per kWh back-out rate is an average figure, the actual filed rates may vary to reflect the actual retailing cost for each class. Obviously, the actual rates should be carefully reviewed when they are filed.
Inclusion of the actual retailing costs in the contestable rate for each class and establishment of a stable and predictable distribution rate should foster competition because LSEs will be free to package other services with the energy commodity thus presenting customers with a variety of options, without fear of a change in retailing costs and distribution rates. In sum, there is no need to modify the Settlement, but it should be clear that the filed rates for each class must reflect its retailing costs.
Calls for a periodic updating of the back-out rate should be rejected. A stable and fixed rate should contribute to the development of competitive market. If the price of generation is less than that included in the back-out rate, LSEs will find it easier to under price RG&E's bundled tariff rate. A price above the back-out rate would act as an incentive to RG&E to divest generating assets.
NYPA's Economic Development Power (EDP)
The proposed Settlement does not contain provisions related to the delivery of EDP. NYPA submits that the Commission should order RG&E to file unbundled retail delivery service rates that accurately reflect its cost of serving NYPA's EDP customers. Since the delivery rates embodied in the Settlement include some of RG&E's production costs, NYPA claims, they would, if applied to EDP, overcharge business customers for the delivery of the NYPA's energy, which would violate state law. Multiple Intervenors supports NYPA's request to clarify that the strandable cost recovery amounts include in the transportation/delivery charge will not apply to EDP customers.
According to RG&E, NYPA did not cite any statutory authority that suggests EDP is entitled to a discount delivery rate. In addition, the company observes that NYPA has no EDP customers in RG&E's service territory. However, the company maintains that when NYPA does have an EDP customer in RG&E's territory, it will provide an appropriate tariff for the delivery of EDP power.
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As the Settlement is silent with respect to EDP delivery rates and because NYPA has no EDP customers in RG&E's service territory, this issue is irrelevant to the determination of the reasonableness of the Settlement. No resolution is recommended.
Provider of Last Resort (POLR)
The Settlement requires that the regulated LSE serve as the POLR until the Commission approves an alternative means of providing such service. In addition, RG&E is committed to working with staff to develop an experimental alternative to provide POLR service on a competitive basis.
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Several parties expressed concerns that customers will not be ensured that there would be POLR. First, the Settlement clearly establishes that the RLSE will fill that function, and, second, the Commission recently stated that:
Although in the long run we would like to see, consistent with the Public Service Law, competitive alternative(s) to the utility as POLR, this issue should be reconsidered after we have more experience with the competitive retail market. For now, the utilities will function as POLRs.(29)
AARP seeks the establishment of a number of standards to ensure reliability, utility consumer protection, and marketing guidelines.
CPB maintains that even though the Commission addressed the issue of slamming with respect to ESCO's in Opinion No. 97-5, and ordered ESCOs to submit plans to prevent slamming, the Commission did not apply the order on slamming to utilities. CPB believes that slamming is a concern, and RG&E should be directed to submit a plan also.
PULP argues that, pursuant to the Settlement, customers may choose to purchase electricity from a LSE that is unrelated to RG&E and unregulated by the Commission. To the extent the Commission's approval of the Settlement appears to endorse the single-retailer model for retail access without express provision for the maintenance of HEFPA protections for all customers, PULP concludes that there will be an abridgment of HEFPA rights. PULP believes that the Commission does not have the power to waive or modify any requirements of HEFPA.
Both staff and Multiple Intervenors respond that PULP has raised similar arguments in other cases, which were rejected. Staff notes that in the Energy Association v. Public Service Commission it was stated "the Courts have recognized that to introduce competition into a monopolist market place and thus lower prices to consumers is well within the Commission's jurisdiction."(30) In addition, staff maintains that this proceeding is not the appropriate forum for PULP's arguments, that the Commission's determination with respect to those issues will be made in the generic COB proceeding as part of the ESCO collaborative process, and that PULP has been an active participant in that process and has taken advantage of the numerous opportunities for comment provided therein.
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In Opinion No. 97-5, the Commission set forth the standard for the POLR and a set of protections for customers served by ESCOs. The Commission required the POLR to conform with the HEFPA protections but not the non-POLR providers. In addition, the Commission generally addressed the issue of slamming, which is one of industry-wide concern that the Commission is cognizant of. If parties wish to challenge the findings in that order, they should do so in that case and not collaterally in the instant proceeding.
Alternative to Dairylea Program
Pursuant to the Settlement, RG&E agrees to make a good faith effort to introduce the Retail Access Program to farm and food processor customers on April 1, 1998 (three months prior to its starting date for other customers) and to introduce the program to those customers outside of the caps that would otherwise limit participation in the Retail Access Program. The signatories believe that RG&E has satisfied the intent of the Commission's Order Concerning Retail Access Proposals(31) in the Dairylea proceeding.
CPB and WEPCO do not agree; they contend that the Settlement is not in compliance with the Dairylea order because the earliest starting date for retail access in the Settlement is April 1, 1998, more than nine months after the June 11, 1997 date specified in the Dairylea order. They complain as well that the Settlement offers an energy only format initially, even though the Commission's Dairylea order requires energy and capacity retail access. Further, WEPCO believes that RG&E will mandate that ESCOs enter into onerous operating agreements, which will preclude market entry by all but the very largest ESCOs. Both parties would require full compliance with the Dairylea order. Finally, CPB recommends that the Dairylea pilot program be implemented in RG&E service territory with the complete set of HEFPA protections and regulations applied to all participating ESCOs.
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Subsequent to the submission of the parties' briefs, the Commission issued a further order(32) in the Dairylea case that sets forth its requirements for the Dairylea access pilot programs. The Commission was aware of the Settlement at the time of its decision, but nevertheless directed that a program be implemented in RG&E territory that differs from the one envisioned in the Settlement. In these circumstances, it is recommended the Settlement be approved on condition that it be modified as necessary to comply with the Commission's recent Dairylea order.
The Settlement provides that if an electric utility or its affiliate requests access to RG&E's system but would deny comparable access to its service territory, RG&E will have the right to petition the Commission for an order requiring that the utility provide comparable access to its system or precluding the other utility from participating in RG&E's Retail Access Program until such time as comparable access is provided to RG&E. Under the Settlement, the filing of such petition will operate automatically to stay the other utility's participation in RG&E's program until the matter is decided by the Commission.
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No party opposes this provision; it appears reasonable and should be adopted.
Pursuant to the Settlement, RG&E will divide existing operations, functionally, into the following activity-based units: distribution unit (DISCO), generating unit (GENCO), regulated load serving entity (RLSE), and at its option a functionally separate holding company (HOLDCO). The company will also set up a structurally separate unregulated load serving entity (ULSE).
The DISCO will continue to carry on RG&E's transmission and distribution service, which will be provided to the ULSE and the RLSE pursuant to regulated tariffs. The GENCO will be responsible for operating RG&E's generating facilities. RG&E's GENCO will consist of a portfolio of nuclear and non-nuclear sources. The output from the nuclear sources will be "dedicated" to regulated load. Output from non-nuclear sources (which will initially serve regulated load) will serve load on a competitively priced basis as customers migrate away from the RLSE. As a practical matter, percentage limits on customer migration to retail access (which are described in an earlier section) act to preserve a retail outlet for RG&E's nuclear power during the term of this Settlement. The RLSE will continue to serve as a POLR and provide bundled service under tariffs to customers who elect to continue receiving bundled service or who do not have a practicable alternative. The ULSE will function as an energy marketer and provider of other energy services both within and outside RG&E's utility service territory.
Pursuant to the Settlement, the signatories support RG&E's petition (attached as Schedule J to the Settlement) to establish a holding company structure in which RG&E will be permitted to operate through one or more regulated companies and one or more unregulated companies, including energy service companies and LSEs.
Whether RG&E conducts its unregulated activities through a HOLDCO or a separate subsidiary of a utility parent, the company will be permitted initially to fund its activities in the amount of $50 million with the approval of this Settlement. Except for the $50 million, RG&E's regulated business segments will not be permitted to fund such unregulated operations, and will not otherwise be allowed to make loans to, nor guarantee nor provide credit support for the obligations of unregulated affiliates.
RG&E supports functional separation for GENCO because divestiture of its generating assets faces three barriers that are surmountable only at extremely high cost, if at all. The first barrier is made up of financial and other constraints arising under the company's many financial and legal agreements, such as its first mortgage indenture, which gives the first mortgage bondholders the right to prevent the release or transfer of the RG&E's generating assets. Obtaining the bondholders' approval would entail substantial cost, most likely in the form of a tender offer to repurchase the bonds at a premium. According to the company, this debt would subsequently have to be refinanced at the then prevailing interest rates.
The second barrier, RG&E notes, is the uncertainty surrounding the treatment of strandable assets in the event of divestiture. The transfer of these major assets would be subject to the approval of the company's bondholders and preferred stockholders, who would require compensation in the form of higher fees, fewer commitments, or more restrictive borrowing terms.
The third barrier to divestiture, according to the company, is unique to the RG&E's nuclear assets, which comprise 83% of the net book value of the company's generation capacity and about 54% of the generating capability. The NRC has authority over the transfer of nuclear facilities, and RG&E reports that the NRC has indicated that any entity seeking to gain ownership of a nuclear facility must have financial health and capabilities at least as strong as the present owner. If a prospective owner is not a regulated utility, RG&E states, the NRC has indicated its intention to require the new owner (or owners) to post credit support for the eventual decommissioning of the facility. According to the company, the expense of this requirement is likely to be so great as to make this barrier insurmountable.
With respect to an immediate structural separation, RG&E notes that it would still require a legal transfer of assets and, as such, each of the three barriers is equally applicable.
In addition, to the three barriers, RG&E points out that the operating license of its wholly-owned Ginna nuclear plant(33) will expire in 2009, and its wholly-owned fossil-fired units are older, smaller, and more tightly integrated into the local electric system than the nuclear units. Finally, RG&E states that it owns only about 4% of the summer generation capability within New York State.
Consequently, the signatories believe that, under the circumstances, the most efficient restructuring includes a functional separation of the company's existing operations and structural separation of the ULSE, along with the option of creating a HOLDCO that would provide its affiliate with services such as corporate governance, administration, legal, purchasing, and accounting. In addition, they believe the Settlement will minimize administrative costs by requiring the company to manage unregulated business as structurally separate entities under the HOLDCO.
According to RG&E, this corporate structure should allow the formation of vigorous competitive businesses that can aggressively seek to provide services that customers demand, and prevent the dampening of competition through unlawful or inappropriate transactions between regulated and unregulated affiliates. The company anticipates that the generation business and the retailing business will ultimately be fully competitive and for the most part unregulated, and that the distribution business will remain regulated as a "common carrier," obligated to maintain the reliability of the distribution system and deliver power through its system on a non-discriminatory basis.
Because the unregulated businesses will be new entities and will not make use of assets that are tied to the company's first mortgage bonds, structural separation for these businesses, the company reasons, does not entail the high cost of structural separation for the existing regulated operations. Structural separation, RG&E states, will ease the administrative burden of keeping unregulated operations separate from regulated operations, and so simplify the process of monitoring regulated operations by regulatory authorities. Structural separation, it was also stated, will insulate the regulated business from the possible financial consequences of poor performance on the part of the unregulated business. Moreover, RG&E argues it will allow investors in today's RG&E, the opportunity to participate in and to profit from the evolution of the industry.
Staff reasons that the Settlement provide a workable solution given the reality of RG&E's heavy nuclear commitments and the potentially significant costs of the divestiture options. According to staff, the proposed corporate structure, in concert with other provisions, will segregate RG&E's generation business and subject the non-nuclear--and potentially the nuclear--operations to market forces on a forward-going basis. The benefits of this proposed plan, staff maintains, are that it will provide improved and correct incentives to RG&E's GENCO for efficient operations and management, an improved playing field for potential competitors of the new GENCO, and the opportunity for lower retail prices.
Many of the opponents to the Settlement prefer divestiture because they believe that the guidelines in the Settlement against self-dealing will not in practice provide adequate protection. To ensure that self-dealing does not occur, they call for the divestiture of any unregulated services. NEV and Entek assert that nuclear plants generally suffer from the poor economics and stringent federal and state licensing and operating requirements but they point out that no such problems exist with RG&E's other generating assets. At the very least, they maintain, the company should be compelled to divest its non-nuclear generating assets within five years with an interim goal of 50% by the end of the third year.
CPB prefers divestiture and would allow formation of a HOLDCO as an interim measure provided it is a corporate parent with regulated and unregulated subsidiaries, but CPB opposes mere functional separation of RG&E's existing business segments because it is concerned about affiliate abuses, cross-subsidization, and the creation of a level playing field.
PULP claims it makes little sense to rush to restructure a massive corporation involving hundreds of thousands of customers, thousands of employees, and billions of dollars in the absence of legislative or a policy based regulatory framework to define or effectuate the new competitive environment. According to PULP, the Commission should postpone action on RG&E's HOLDCO petition until an independent system operator is in place and until enabling legislation has been enacted to restructure the electric industry.
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The functional separation of the GENCO will essentially require it to behave as a separate company in order to compete in the market. Its performance will be judged based upon its individual financial reports, and it will likely craft distinct strategic marketing plans. Generating plants should continue to operate provided their anticipated future costs are less than anticipated market prices.
The regulated DISCO will provide regulated transmission and distribution services to LSEs and will own all of RG&E's generating assets either directly or through ownership of the GENCO. The RLSE will provide regulated retail energy services and will continue to serve as a POLR, at least during the term of the Settlement.
The HOLDCO will provide the company with the flexibility to enter unregulated businesses in a convenient and economical manner. Thus, the petition to form the HOLDCO and the $50 million funding should be approved.
This corporate structure in conjunction with the incentives to operate the generating plant in an efficient manner by exposing it to market forces, the commitments of RG&E to maintain the reliability of its system as noted supra, and the safeguards governing the transactions of the various affiliates, discussed next, is reasonable and should be adopted. In addition, the functional separation of RG&E's business segments avoids the high cost of divestiture or structural separation of the existing plant.
PULP's concerns about the creation of an independent system operator and the passage of enabling legislation are not a bar to approval of the restructuring. As noted above in the introduction to the Retail Access Program, the signatories recognize that the functioning of a statewide energy and capacity market is a crucial factor in the ability of RG&E to implement its Retail Access Programs. If it is not established in time, the signatories agree to address any such problems in good faith. Finally, with respect to the HOLDCO, PSL 70, 107 and 108 already give the Commission the authority it needs to approve the formation of the HOLDCO and the restructuring of RG&E.
Affiliate Relationships/Competitive Practices/Code of Conduct
The Settlement sets forth principles relating to the affiliate relationships, code of conduct, cost allocations, protections and restrictions applicable to the HOLDCO company and competitive subsidiaries. They are contained in Schedule I, attached to the Settlement.
Staff observes that most of the Settlement's provisions in this regard were based on standards developed in other Commission proceedings and were modified as appropriate during the negotiation process.
With respect to the code of conduct and affiliate relationships, the Attorney General believes that staff will not have the resources to supervise the operations of all the affiliates. While IPPNY/Enron and WEPCO do not oppose RG&E forming ULSEs, they contend that the code of conduct is insufficient to protect against affiliate abuses and expressed numerous concerns. Generally, they suggest restrictions that would completely separate the marketing affiliate from the parent or utility and mandate a level competitive playing field. For example, IPPNY/ENRON and WEPCO oppose the Settlement provisions that allow RG&E to incur cost on behalf of its affiliates and allocate those costs to the appropriate subsidiaries, and to release information to competitors upon obtaining the consent of the customers.
A great concern of the opponents with respect to restructured corporate organization is the use of RG&E's name. WEPCO states that the most significant source of a utility affiliate's market power is its ability to trade on the utility's name, status, and reputation. Consequently, WEPCO proposes that RG&E's affiliates be barred from using RG&E's name, logo, and trade marks or trade on its status and reputation in any manner. To prevent RG&E from abusing its market power, WEPCO would prohibit any of RG&E's affiliates from marketing in the company's service territory for the first two years of retail access or until 20% of customers take service from other ULSEs. NEV and Entek generally agree with this approach, however, the Attorney General and CPB would require the affiliates to pay a royalty to RG&E for the use of its name if a prohibition is not adopted.
RG&E responds that the proscription on the use of its name is unnecessary, in opposition to the interests of consumers, and contrary to the economic development policies of New York State because numerous large competitive businesses such as Enron are already beginning to make their presence known in the market place through national advertising designed to establish their brands in the minds of consumers. In regard to interests of customers, RG&E notes that they deserve to know with whom they are dealing because they may find it advantageous to deal with a local firm, and to deny them this information is to deny them that advantage. Finally, the company believes a proscription is contrary to the economic development policies of New York State because it may well result in the inability of RG&E to survive and prosper.
* * *
Most of the criticisms related to the code of conduct arise because RG&E is not divesting or structurally separating existing operations, which were found to be impractical in the preceding section. To fashion a code of conduct that would satisfy potential competitors is well nigh impossible. The Settlement's provisions with respect to the conduct of affiliates appear to be comprehensive, and as staff notes, are based on standards approved in prior Commission proceedings. Obviously, such document cannot cover every conceivable action, rather they contain broad principles that establish fair rules of conduct. If abuse arises, there is no doubt that petitions will be forthcoming. At that time, the particular circumstances and facts can be reviewed and the conduct of RG&E and its affiliates judged according to the applicable law and the principles set forth in the code of conduct. In addition, if the circumstances render RG&E's rate of return on investment unreasonable, inadequate, or excessive for the provision of safe and adequate service, the Settlement reserves for the Commission the right to take action on the level of the company's rates.
Finally, no proscriptions, prohibitions against competition, or royalty payments should be imposed on RG&E. As the company notes they are unnecessary and ignore the fact that the Settlement is an integrated whole, and that the rate cuts implemented by the Settlement are justified by, among many other things, the benefits that the company expects to receive through the operation of unregulated businesses.
State Action Doctrine
Upon adoption of the Settlement, RG&E may be immune from anti-trust liability if it is acting pursuant to a clearly articulated state policy and the conduct is closely supervised by the State. RG&E may be eligible for this immunity if its conduct, although anti-competitive, is shown to be consistent with the Settlement, and is being supervised by the Commission. IPPNY/Enron and Multiple Intervenors believe that the Commission is not in a position to monitor such conduct, uncover possible violations and enforce the anti-trust laws. Therefore, they request the Commission to declare that the Settlement is not a policy designed to supplant competition with regulation, that not all conduct will be supervised closely by the State and, therefore, the state action immunity does not apply.
RG&E has no doubt that the State has a general policy favoring anticompetitive activity, however, the company believes that IPPNY/Enron, and Multiple Intervenors' proposals to nullify the state action doctrine is misguided and probably not feasible. RG&E explains that the state action doctrine affords private parties immunity from antitrust liability where two essential conditions are satisfied: First, the State must have articulated a clear and affirmative policy to allow the conduct that was challenged(34) such as the regulatory structure governing public utilities in New York. Second, the State must engage in active supervision of the private conduct at issue, and must ensure that the immunity applies only where private action is in furtherance of the State's chosen regulatory policy.(35) Contending that the doctrine immunizes private action because a state has authorized and supervised particular conduct by a private party who has acted in reliance on such authority and supervision, RG&E argues that the immunity cannot be withheld on the ground that a state has a general policy against anticompetitive conduct.
Furthermore, RG&E observes that a key condition of an effective regulatory regime is reasonable assurance to private parties that, in complying with state regulation, they are not exposing themselves to civil or criminal liability. Removal of the state action doctrine, the company notes, would vastly increase the risk and complexity of regulatory compliance by public utilities and would require that, before undertaking any business transaction or initiative, the utility must attempt its own antitrust review to determine whether the action might be found to be anticompetitive. Such an analysis, RG&E maintains, would greatly impede, or even paralyze, utilities' efforts to run their businesses.
* * *
The request to declare the state action doctrine inapplicable is too far reaching and premature. Perhaps the conduct that may ultimately be challenged is one that the Commission will want to promote and protect via the state action doctrine. Assuming for the sake of argument that the Commission could strip RG&E of protection provided by the state action doctrine, such an action may frustrate Commission policy in the future. Consequently, no such declaration should be announced at this time.
Attached as Schedule H to the Settlement is a list of operating functions. The responsibility for these functions must be divided between the DISCO and LSEs. While the schedule indicates each entity's primary and secondary responsibilities, the actual operating agreement will be drafted in consultation with an Advisory Council to be made up of the parties and will be filed on December 1, 1997.
WEPCO interprets schedule H as a list of the duties that ESCOs must undertake and believes that they create an unreasonable barrier to entry for all but the largest ESCOs. Other parties, including AARP, PII, IPPNY/Enron, CPB, and PULP also submitted ESCO related comments concerning oversight, metering and billing, etc. Staff responds that these concerns are premature because the actual document has not yet been drafted.
* * *
No decision on the contents of the operating agreement should be rendered now. Instead, as staff suggests, concerns about responsibilities of the ESCOs, LSEs, and the DISCO should await the filing of the operating agreement. With respect to the other ESCO- and LSE-related concerns the Settlement specifically states that it is not in full compliance with the tasks outlined in Opinion No. 96-12. In addition, the Commission has established policies for ESCOs and will continue to address these issues in another proceeding.(36) Thus no recommendations are offered here with respect to these issues.
In addition to provisions relating to dispute resolution, precedent, and modifications, the Settlement also addresses two outstanding cases. Once this Settlement is approved and after any appeals from such approval are exhausted or the time to appeal has expired, whichever is later, RG&E will petition the Appellate Division of the Supreme Court for permission to withdraw as a party to the appeal in the Article 78 proceeding brought to challenge Opinion No. 96-12, Energy Association v. Public Service Commission (Sup. Ct. Albany Co. Index No. 5830-96), and, as mentioned above, to withdraw the company's pending Article 78 proceeding brought to challenge the Commission's action with respect to the 1996 Settlement, Rochester Gas and Electric Corporation v. Public Service Commission (Sup. Ct. Albany Co. Index No. 6616-96).
According to the Attorney General, the Commission should not consider the withdrawals from litigation as a substantial benefit because it is convinced that lower courts decisions will be upheld by the Appellate Division.
* * *
The Settlement removes all doubt about the outcome of these proceedings and it does so without the potential to delay the implementation of the Retail Access Program. Contrary to the Attorney General's assertion, the withdrawals from litigation will have a substantial beneficial value.
First, although the Settlement is silent on the subject, several parties proposed that LSEs should be required to maintain, and disclose to their customers, current and specific information about their sources of generation. CPB notes that some customers would be willing to pay a premium for environmentally friendly "green" electricity supplies. Similarly, PII calls for an objective statement about resources used to supply power, which discloses the fuel mix and emissions characteristics.
RG&E responds that disclosure of accurate, up-to-date information about the identity, fuel mix, and emissions profiles of generation sources would be both expensive and extremely difficult. According to RG&E, LSEs may receive generation from a substitute source or may be forced to purchase on the spot market to ensure that its customers' load and delivered energy remain in balance. Furthermore, the company asserts that if, as CPB avers, customers are willing to pay a premium for "green" power, then surely LSEs will compete for that portion of the market by offering "green" power packages, disclosing their generation sources as a positive selling point.
Staff points out that requirements applicable to competitive retail energy service providers, i.e., ESCOs or LSEs, are addressed in an opinion and order that was issued May 19, 1997.(37) Since that decision, and not the decision on this Settlement, governs such issues, staff suggests that they need not be further addressed in this proceeding.
Next, PII proposes that suppliers of retail electric service be required to meet a minimum emission portfolio standard because newer generation facilities are subject to stricter environmental standards than older plants, which may confer a cost advantage on older plants. The proposed standard is intended to eliminate this cost advantage.
RG&E replies that PII's real purpose is to impose indirectly new environmental requirements. Staff agrees; it observes that the Settlement does not mention nor would it determine the environmental regulations applicable to old and new generation. Since PII's proposal is neither governed by nor an element of the Settlement, staff argues, it does not impact the reasonableness thereof. Multiple Intervenors adds that the Commission has already considered PII's proposal(38) in Opinion No. 96-12 and did not adopt it.
* * *
As a procedural matter, both requests should be denied because each one was considered and rejected in a separate Commission proceeding.
The Commission has established the following standard to test the reasonableness of any proposed settlement:
a. A desirable settlement should strive for a balance among (1) protection of the ratepayers, (2) fairness to investors, and (3) the long term viability of the utility; should be consistent with sound environmental, social, and economic policies of the Agency and the State; and should produce results that were within the range of reasonable results that would likely have arisen from a Commission decision in a litigated proceeding.
b. In judging a settlement, the Commission shall give weight to the fact that a settlement reflects the agreement by normally adversarial parties.(39)
In reviewing this Settlement, one point has been constantly kept in mind: the Settlement is an integrated whole and not an assortment of separable components. There were many compromises made during negotiations. Each signatory weighed each provision against a compromise on that provision, or with a concession elsewhere. Furthermore, each provision has been examined in this recommended decision to determine if it is reasonable and in the public interest in accordance with the guidelines established by the Commission.
With one exception, not only have the individual provisions been recommended as reasonable, but also the overall Settlement has been found reasonable. The exception involves the Dairylea program, which the Commission has already considered as noted above.
Generally, it has been recommended that the revenue reductions are reasonable and overall provide ratepayers significant benefits over the five-year term of the Settlement. In addition, the ratepayers will no longer be liable for credits arising from flex-rate discounts and past incentives. Furthermore, the rates will be redesigned in accordance with marginal costs, which should not only remove some of the inter- and intra-class subsidies, but also bring the rates close to those expected when the electric market is open to competition.
With respect to the Retail Access Program, it has been recommended that the Settlement be approved because the phase-in of competition proceeds at a pace that will allow RG&E to overcome problems related to its reliance on nuclear power for roughly half its generation and the existence of load pockets, while at the same time, give customers access to retail competition in the near future.
The average back-out rate of $.032 per kWh appears to be reasonable in that it equals the To-Go Costs of RG&E's fossil and hydro generation and power purchases exclusive of Kamine. Also RG&E is at risk for this generation, i.e., if a customer elects to purchase power from other sources in the competitive market, the company will absorb the financial loss and not pass it along to its other customers. This should create a fair market for competition. In addition, if the market price exceeds $.032 per kWh, it will create an incentive for RG&E to divest itself of its non-nuclear generating assets.
One caveat has been raised in the recommended decision concerning the allowance for retailing costs included in the average $.032 per kWh back-out rate. It has been recommended that retailing cost, especially for residential and small commercial classes, be accurately estimated and reflected in the back-out rates when they are filed. It has also been recommended that RG&E present a plan to open to competition all aspects of metering, including the ownership of the meters, at the end of the term of the Settlement.
The proposed restructuring of RG&E in conjunction with the incentives to operate the GENCO in an efficient manner by exposing it to market forces, and the safeguards governing the transactions of the various affiliates have been found to be reasonable because they will avoid the high costs of divesture or structural separation, especially of the nuclear plants. While RG&E's ULSE will benefit by being permitted to use the corporate name and up to $50 million of funding from the company, the ULSE will be an added source of competition, the benefits of which should redound to the electric consumers.
Although all of the signatories did not submit their litigation positions, RG&E did. It is clear from reviewing the company's October 1, 1996 submission that RG&E made substantial concessions especially with respect to rate reductions. Multiple Intervenors notes that it would have argued for larger rate decreases, a faster phase-in of retail access, and a greater sharing of stranded costs during the transition period.
It should also be kept in mind that a number of parties opposed the Settlement and they litigated their positions. After considering the facts and reasons behind their positions, which are set forth in the body of this decision, it is nonetheless recommended that the Commission adopted the Settlement. It is recognized that much detailed work remains and disputes may arise, for example, in the retailing allowance contained in the back-out rate for residential customers. However, these disputes can be addressed at the time they arise and speculation as to their outcome should not preclude a finding that the Settlement is reasonable.
July 16, 1997
FOR ROCHESTER GAS AND ELECTRIC CORPORATION:
Nixon, Hargrave, Devans & Doyle (by Robert J. Bird, Richard N. George, and Stanley W. Widger, Jr., Esqs.), Clinton Square - P.O. Box 1051, Rochester, New York 14603
FOR DEPARTMENT OF PUBLIC SERVICE STAFF:
Michelle Phillips, Esq., Three Empire State Plaza, Albany, New York 12223-1350
FOR ATTORNEY GENERAL OF THE STATE OF NEW YORK:
Glen C. King, Esq, The Capitol, Albany, New York 12247
FOR NEW YORK STATE CONSUMER PROTECTION BOARD:
Anne Curtin and James Warden, Esqs.
99 Washington Avenue, Suite 1020, Albany, New York 12210
FOR NEW YORK POWER AUTHORITY:
Eric J. Schmaler, Esq., 1633 Broadway, New York,
New York 10019
FOR AMERICAN ASSOCIATION OF RETIRED PERSONS:
Ward, Sommer & Moore, LLC (by Douglas H. Ward, Esq.)
122 South Swan Street, Albany, New York 12210
FOR PUBLIC INTEREST INTERVENORS AND FOR PACE ENERGY PROJECT:
David Resnick, Esq., 78 North Broadway, White Plains, New York 10606
FOR IPPNY AND ENRON TRADE & CAPITAL RESOURCES:
Read & Laniado (by Kevin Brocks, Esq.)
23 Eagle Street, Albany, New York 12207
FOR MULTIPLE INTERVENORS:
Couch, White, Brenner, Howard & Feigenbaum (by Robert M. Loughney, Esq.) 540 Broadway P.O. Box 2222, Albany, New York 12201
FOR RETAIL COUNCIL OF NEW YORK:
Cohen, Dax & Koenig (by Paul Rapp, Esq.)
90 State Street, Albany, New York 12211
FOR WHEELED ELECTRIC POWER COMPANY:
Joel Blau, Esq., 32 Windsor Court, Delmar, New York 12054
FOR CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.:
John F. Gallagher, Esq., 4 Irving Place, New York, New York 10003
FOR CONSOLIDATED NATURAL GAS COMPANIES:
Whiteman, Osterman & Hanna (by Michael Whiteman, Esq.,)
One Commerce Plaza, Albany, New York 12260
FOR NEW YORK STATE ELECTRIC & GAS CORPORATION:
Huber Lawrence & Abell (by Andrew Fisher, Esq.)
605 Third Avenue, New York, New York 10158
Jerome Bowe, 104 Brentwood Drive, Penfield, New York 14526
Charles A. Straka, 6 Oakwood Lane, Fairport, New York 14405
APPENDIX B - Settlement Agreement Attachments
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- Part A (431KB PDF)
- Part B (522KB PDF)
ROCHESTER GAS AND ELECTRIC CORPORATION
LIST OF ABBREVIATIONS
AARP - American Association of Retired Persons
ATTORNEY GENERAL - New York State Department of Law
CASH O&M - Cash Operation and Maintenance
CPB - New York State Consumer Protection Board
DAIRYLEA - Dairylea Cooperative Inc.
DISCO - Distribution Unit
DSM - Demand Side Management
ENTEK - Entek Power Services, Inc.
ESCO - Energy Service Company
FERC - Federal Energy Regulatory Commission
GDP - Gross Domestic Product
GENCO - Generating Unit
gWh - Gigawatt-hour
HEFPA - Home Energy Fair Practices Act
HOLDCO - Holding Company
IPPNY\ENRON - Independent Power Producers of New York, Inc. and Enron Capital & Trade Resources
ISO - Independent System Operator
KAMINE - Kamine/Beisco -Allegany L.P.
KCAM - Kamine Cost Adjustment Mechanism
kW - Kilowatt
kWh - Kilowatt-hour
LSE - LOAD SERVING ENTITY
MBIS - Metering, billing, and Information services
NEV - New Energy Ventures, Inc.
NRC - Nuclear Regulatory Commission
NYPA - New York Power Authority of the State of New York
PII - Public Interest Intervenors
POLR - Provider of Last Resort
PSL - Public Service Law
PULP - Public Utility Law Project of New York, Inc.
RETAIL COUNCIL - Retail Council of New York
RG&E - Rochester Gas and Electric Corporation
RSLE - Regulated Load Serving Entity
SAPA - State Administrative Procedure Act
SBC - System Benefits Charge
SC - Service Classification
STAFF - New York State Department of Public Service Staff
ULSE - Unregulated Load Serving Entity
WEPCO - Wheeled Electric Power Company
4. RG&E will petition the court for permission to withdraw as a party to the appeal in the Article 78 proceeding brought to challenge Opinion No. 96-12, Energy Association v. Public Service Commission (Sup. Ct. Albany Co. Index No. 5830-96), and to withdraw the company's pending Article 78 proceeding brought to challenge the Commission's action with respect to the 1996 Settlement, Rochester Gas and Electric Corporation v. Public Service Commission (Sup. Ct. Albany Co. Index No. 6616-96).
5. Cases 95-E-0673 et al., Rochester Gas and Electric Corporation, Order Approving Terms of Settlement Agreement With Changes, (issued June 27, 1996), which was restated in Cases 95-E-0673 et al., Rochester gas and Electric Corporation, Opinion No. 96-27 (issued September 26, 1996). The Commission's modification of the 1996 Settlement is the subject of an Article 78 proceeding that will be withdrawn upon approval of the Settlement.
16. As noted in the preceding section, RG&E will be permitted to reflect adjustments in its distribution access tariff related to all prudently incurred cost for the shut-down and decommissioning of nuclear generating facilities.
17. To achieve its full 10% reduction in rates, CPB estimated it would need a $415.8 million reduction in rate base along with its other adjustments, which, CPB claims, would result in 22.5% of the strandable costs being allocated to the stockholders.
33. RG&E is also a minority owner of the Nine Mile Point 2 Nuclear Plant, which has a longer remaining life, and a minority owner of the fossil-fired Oswego Unit 6, which provides useful capacity to the Statewide network, but is rarely dispatched.
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