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In re Public Service Electric and Gas Company's Rate Unbundling

New Jersey Superior Court, Appellate Division

April 13, 2000


Before Judges King, Carchman and Lefelt.

The opinion of the court was delivered by: King, P.J.A.D.

Argued: March 8, 2000

On appeal from the New Jersey Board of Public Utilities.



This is a consolidated appeal from two decisions of respondent the Board of Public Utilities (BPU): (1) its Final Decision and Order on the rate unbundling, stranded costs, and restructuring filings of respondent Public Service Electric and Gas Company (PSE&G), and (2) its bondable stranded cost rate order (BSCRO) on PSE&G's petition to finance, or securitize, its recovery-eligible stranded costs.

Co-Steel Raritan (Co-Steel), one of PSE&G's largest commercial customers, appeals from that portion of the Final Decision which ordered payment of stranded cost charges mandated by the Electric Discount and Energy Competition Act of 1999, N.J.S.A. 48:3-49 to -98, L. 1999, c. 23, effective February 9, 1999 (the Act), despite Co-Steel's special contract with PSE&G. The Division of the Ratepayer Advocate (RA) and New Jersey Business Users (NJBUS), a group of large industrial and commercial customers, appeal from specific findings in the Final Decision and on procedural due process grounds, contending that they were denied due process when the BPU refused to reopen the record after passage of the Act and BPU decided the securitization issue without holding hearings, among other procedural irregularities. The RA is also a respondent on the issues raised by Co-Steel. Briefs have been filed on behalf of six intervenors in the proceedings before the agency:

Jersey Central Power & Light Company (GPU), Rockland Electric Company (RECO), New Jersey Commercial Users (NJCU), Enron Energy Services (Enron), Independent Energy Producers of New Jersey (IEPNJ), and Tosco Refinery Company (Tosco).

The administrative proceedings leading up to these decisions were unusual in many ways: hearings on the unbundling, stranded costs, and restructuring issues were held before an administrative law judge before the Act was passed; the securitization issue invited comments from interested parties but no hearings. Quasi-legislative public hearings were held on deregulation three years before the Act actually was introduced in the Legislature. The BPU's Final Decision relied heavily on a negotiated agreement between PSE&G and seven intervenors which had an opportunity to comment on the agreement. Despite the unusual procedural irregularities, however, we conclude that all parties had ample opportunity to be heard on all aspects of both decisions. We find no denial of due process and no fundamental unfairness. We affirm.

To assist the reader in understanding the terms and acronyms we use we provide a Table of Acronyms.



From the early 1900s until the Act was passed in 1999, the electric power industry had been composed of vertically-integrated public utility companies. Each company owned power generation plants, plus transmission, distribution, and customer service facilities. The companies had virtual monopolies over their geographically-defined service territories. The charges for all services ÄÄ power supply, electric transmission and distribution, and such customer services as connects and disconnects, metering, billing, and account administration ÄÄ were "bundled" and billed at a single price.

In the late 1970s, electricity rates increased dramatically; by 1985 New Jersey consumers were paying about 50% above the national average for electricity. This situation persisted into the late 1990s. Although such factors as a higher cost of living, higher energy taxes, tighter environmental standards, and a lack of indigenous energy supplies played a part in this rise in rates, a major factor was the high average power production costs in New Jersey. Power production costs were high due to expensive utility-owned nuclear power plants and expensive power purchase agreements with nonutility generators (NUGs).

Competition began in the production aspect of the electric power industry after Congress enacted the Public Utility Regulatory Policies Act of 1978, 16 U.S.C.A. § 2601-2645 (PURPA), which provided incentives to develop nonutility electricity generation. Because of various federal initiatives, by 1997 there were a growing number of power producers and suppliers offering power for sale regionally at competitive prices. In fact, 19% of the electricity consumed by New Jersey customers in 1997 was purchased from independent power producers.

New Jersey's move toward competitive electric power markets in the 1990s paralleled similar regional and national developments. David Pettinari, You Can't Always Get What You Want--Will Two Recent State Court Decisions Tarnish the Political Promise of Electricity Industry Deregulation?, 76 U. Det. Mercy L. Rev. 501, 519 (1999). In 1992 Congress enacted the Energy Policy Act, 42 U.S.C.A. §§ 13201-556, which supported competition and choice in the electricity marketplace, and in May 1995 the Federal Energy Regulatory Commission adopted rules which paved the way for a competitive wholesale power market. Pennsylvania, New York, Massachusetts, New Hampshire, Rhode Island, Vermont, Maine, and California passed legislation or announced plans that would initiate retail choice for electric customers during 1998 and 1999. Michigan introduced deregulation through an administrative order before legislation on the matter was adopted. Pettinari, at 529-30.

In March 1995, the New Jersey Energy Master Plan Committee, under the leadership of Governor Whitman and Herbert Tate, president of the BPU, released the New Jersey Energy Master Plan Phase I Report, which provided a policy framework for the transition from power industry monopolies to competitive markets. The Master Plan recommended several short-term measures to prepare for the transition to competition, including passage of legislation providing for rate flexibility to help retain "at risk" customers, and it directed the BPU to investigate changes to the structure of the electric power industry as a means of lowering the cost of electricity in this State. In July 1995, Governor Whitman signed into law P.L. 1995, c. 180, the Rate Flex and Alternative Regulation Act, N.J.S.A. 48:2-21.24 to -30, which mandated that the BPU implement programs which promote a transition to a market-based competitive environment in the energy industry. For example, the Rate Flex Act allowed electric utilities to enter into "off-tariff" or discounted rate agreements with business customers in order to induce them to remain in New Jersey.

By an order of June 1, 1995 the BPU initiated Phase II proceedings to investigate and develop a long-term policy for implementing a competitive marketplace for electricity. The order directed interested parties to participate through comments and reply comments to the BPU between July and October 1995. Four informal working groups composed of representatives of various interest groups and stakeholders were formed to explore the issues related to restructuring the electric industry. They submitted reports to the BPU in February 1996. The BPU staff prepared a status report based on the four working-group reports and by an order of June 27, 1996 the BPU adopted the status report's recommendations regarding the procedural steps necessary to move toward restructuring.

The BPU adopted a two-step approach to gathering additional information: (1) it ordered formal public hearings and a concurrent public comment period for written comments, and (2) it ordered informal negotiating sessions with representatives of the various interest groups in an attempt to reach a consensus on the salient issues. The status report was distributed for public comment, and public, legislative-type hearings were conducted on July 18, 1996, in Trenton; on July 30, 1996, in Atlantic City; and on August 7 and 8, 1996, in Newark. Written comments were received by August 16, 1996.

In June 1996, negotiating teams were formed; they included representatives from all stakeholders and interest groups: the four New Jersey utilities ÄÄ PSE&G, RECO, GPU, and Atlantic Electric Company (Atlantic); consumer groups; environmental interests; energy service companies; independent power producers; power marketers (nonutility companies that buy and then resell electricity); industrial, business, and commercial customers; independent contractors; labor unions in the electric industry; public power associations; local government, and the Director of the RA. The interest groups were permitted to have technical advisers help with the negotiating. Negotiating sessions occurred on a weekly basis from June 27, 1996 through October 25, 1996.

On January 16, 1997 the BPU released "Restructuring the Electric Power Industry in New Jersey: Phase II Report Proceeding Proposed Findings and Recommendations Report" (draft report). Three public hearings to receive oral comments on the draft report were held on February 4, 1997, in Newark; on February 5, 1997, in Camden County; and on February 11, 1997, in Trenton. The BPU heard testimony from forty-two parties and accepted written comments from thirty-nine parties through February 28, 1997. After review of the comments and testimony, the BPU prepared "Restructuring the Electric Power Industry in New Jersey: Findings and Recommendations (Final Report)," which was adopted and released by an order dated April 30, 1997.

The 173-page Final Report's primary recommendation was that by October 1998 retail electric customers in New Jersey should commence to have the ability to choose their electric power supplier, and by July 2000 all New Jersey retail customers should be able to exercise that choice. The Final Report also recommended rate reductions of 5 to 10% while retail competition was phased in. The BPU announced it was looking "forward to working with the State's legislators during 1997 to craft legislation which will provide the foundation and necessary legal authority for the changes" it recommended.

The BPU's April 30, 1997 order adopting the Final Report also directed the four utility monopolies in New Jersey to submit filings in accordance with the guidelines and principles in the Final Report. The Final Report's "Implementation Steps and Schedule" directed each of the four companies to submit three filings ÄÄ a rate unbundling petition, a stranded cost petition, and a restructuring plan ÄÄ by July 15, 1997. The BPU expected that several of the issues to be addressed in the filings ÄÄ standards for fair competition, affiliate relationship standards, analysis of market power, and mechanics for the phase-in of customer choice ÄÄ would be "pulled out of the individual utility proceedings and reviewed generically." The BPU intended to complete its review of each filing and render a final decision by October 1998 to meet its deadline for the introduction of retail competition by that month. The BPU set forth specific guidelines for the matters to be addressed in the three filings.

By an order of June 25, 1997 the BPU directed its Audit Division to initiate management audits on the four electric utilities and to solicit the assistance of consulting firms to perform the audit. After issuing a request for proposals, and receiving and reviewing several proposals from independent auditors, the BPU selected Vantage/ICF Consulting (ICF) to perform an audit of PSE&G's filings.

On July 11, 1997 the BPU issued an order which established procedures for the filings: the utility's rate unbundling and stranded cost filings would be transmitted to the Office of Administrative Law (OAL) for hearings and an Initial Decision; the BPU would retain the restructuring plan filings for its own review and, if necessary, for hearings. The BPU intended to issue a Final Decision and Order in all of the matters before the anticipated start date of competition.

On July 15, 1997 PSE&G submitted a single filing containing its rate unbundling, stranded costs, and restructuring proposals, as well as prefiled direct testimony of seven witnesses. The BPU transmitted the unbundling and stranded cost portions of the filing to the OAL, where ALJ Louis McAfoos was assigned to the matter. The BPU retained the restructuring portion of the filing for its own review. The ALJ granted intervenor and participant status to over thirty groups, representing the diverse concerns of utilities, customers, suppliers, labor, and environmental groups. The BPU also granted intervenor and participant status to interest groups.

On September 25, 1997 the BPU issued an order establishing procedures for the restructuring filings, identifying issues with generic implications, and directing the creation of working groups to review the generic issues and submit status reports by January 10, 1998. On January 28, 1998 the BPU established a procedural schedule for review of generic restructuring issues, e.g., divestiture of generation assets, functional separation plans, and mechanics of the phase-in of retail competition.

In November 1997, thirteen intervenors and the RA submitted the prefiled testimony of twenty-five witnesses. PSE&G filed the rebuttal testimony of ten witnesses. ALJ McAfoos conducted a status conference on January 16, 1998 and on January 24 issued a hearing schedule for the unbundling and stranded cost matters. In late January 1998, the intervenors filed the surrebuttal testimony of eighteen witnesses. On January 29, 1998 the BPU released ICF's audit report on PSE&G's unbundling and stranded cost filings, and on March 5, 1998, it released ICF's report on PSE&G's restructuring filing.

The OAL conducted twenty days of evidentiary hearings on the unbundling and stranded cost matters, from February 9 to March 18, 1998. In April 1998, after the hearings were completed, the parties filed briefs. On the restructuring matter, BPU Commissioner Carmen Armenti held twenty days of hearings between April 27 and May 28, 1998. Thirteen intervenors, the RA, and PSE&G filed the testimony of forty-five witnesses. Representatives of ICF and the three other consulting firms which submitted audit reports on the four utilities' restructuring filings also testified. Briefs on the restructuring issues were filed in June and July 1998.

ALJ McAfoos issued an Initial Decision on the rate unbundling and stranded cost matters on August 14, 1998. The parties filed exceptions and replies to exceptions in October 1998. One matter the ALJ did not resolve was the quantification of stranded costs, although he offered guidance on how the amount should be calculated. After the parties conferred on the issue but could not agree on a stranded cost total, the BPU had ICF prepare a report on the quantification of stranded costs. The BPU relied on the ICF report in its Final Decision.

Meanwhile, in September 1998, a draft of the deregulation bill was introduced in the New Jersey Legislature. The final draft was introduced in both the Assembly and Senate on January 25, 1999. On January 28, 1999 the Assembly passed the bill by a vote of sixty to nine and the Senate passed it by a vote of twenty-seven to six. It was approved on February 9, 1999, the effective date of the Act.

The Act establishes the framework and time schedules for deregulation and restructuring of electric utilities in New Jersey. Statement attached to Assembly Bill A-16, P.L. 1999, c. 23. It mandates a 5% rate reduction by August 1, 1999, the date at which retail competition was to begin, and at least a 10% rate reduction within three years of that date. N.J.S.A. 48:3-52(d) and 3-53(a). The maximum rate reduction must be sustained at least until the end of the fourth year after August 1, 1999 (July 31, 2003). N.J.S.A. 48:3-52(j). As of August 1, 1999, electric companies had to unbundle their rates and separately identify charges for discrete services, such as generation, distribution, and transmission. N.J.S.A. 48:3-52(a). The Act also establishes "shopping credits" for customers who choose to purchase generation service from an alternative supplier; this reduces their rates and offers an incentive to shop for alternative electric suppliers. N.J.S.A. 48:3-52(b).

Although the Act does not mandate total divestiture, it allows utilities to functionally separate their generation assets and transfer them to an affiliate. N.J.S.A. 48:3-59. The utilities are permitted to recover stranded costs ÄÄ the generation plant costs which the utility is at risk of losing when the supply market is opened to competition ÄÄ through a limited-duration (up to eight years) nonbypassable market transition charge (MTC). N.J.S.A. 48:3-61(a). Starting on August 1, 1999 the utilities may collect a nonbypassable Societal Benefits Charge (SBC) designed to recover the costs for social programs, nuclear plant decommissioning, demand-side management (DSM) programs, environmental programs, and consumer education programs. N.J.S.A. 48:3-60(a). They are also permitted to impose a nonbypassable transition bond charge (TBC) (for up to fifteen years) in order to recover stranded costs. N.J.S.A. 48:3-62(a). The transition bonds, issued pursuant to a BSCRO, finance eligible stranded costs. N.J.S.A. 48:3-64(a). Financing, or securitizing, stranded costs through the issuance of asset-backed securities mitigates the rate impact of stranded cost recovery because the interest rates through financing are lower than the utility's historic cost of capital.

On February 11, 1999, consequent upon passage of the Act, the BPU set a schedule to render its decision, but also urged the parties to attempt to negotiate a settlement by March 3, 1999. On March 8, 1999 the Mid-Atlantic Power Supply Association (MAPSA) moved to reopen and supplement the record in the PSE&G unbundling and stranded cost proceedings. The RA and NJBUS supported MAPSA's motion; PSE&G opposed it. The BPU denied the motion on March 25, 1999 finding there was ample evidence in the record for its decision and that the entire proceedings had been conducted in contemplation of deregulation.

On March 17, 1999 eight parties submitted a proposed stipulation of settlement (Stipulation I): they were PSE&G, New Jersey Transit Corporation, Tosco, NJCS, Enron, IEPNJ, International Brotherhood of Electrical Workers Local 94, and National Resources Defense Council. On March 29, 1999 six other parties submitted an alternative settlement proposal (Stipulation II): they were the RA, NJBUS, MAPSA, New Energy Ventures, New Jersey Industrial Customers Group, and New Jersey Public Interest Intervenors (excluding the Natural Resources Defense Council). In April 1998 both groups of negotiators submitted comments on each other's stipulations.

The BPU held a public agenda meeting to consider the proposals and on April 21, 1999 issued a summary order, finding Stipulation I more financially prudent and consistent with the Act's requirements than Stipulation II. On August 24, 1999 the BPU issued its Final Decision and Order, which supplemented and elaborated on the April summary order. It announced that PSE&G was permitted to securitize up to $2.4 billion of its stranded costs.

On June 8, 1999, after the BPU issued its summary order but before it issued its Final Decision, PSE&G filed a petition with the BPU, seeking a BSCRO to securitize $2.4 billion in stranded costs. On August 11, 1999 the RA filed comments, raising thirteen arguments in opposition to PSE&G's financing petition and requesting that evidentiary hearings be held on the issue. On August 24, 1999 the BPU held a public meeting at which it rendered the decision that no hearings were required. On September 17, 1999 the BPU denied Co-Steel's and NJBUS's motions to intervene in the securitization proceeding and issued a BSCRO approving PSE&G's securitization.

Co-Steel and NJBUS have filed separate appeals from the Final Decision and Order in the unbundling, stranded costs, and restructuring matter and from the BSCRO. (A-1108-99T3 and A-772-99T3 are Co-Steel's appeals from the restructuring and financing matters; A-643-99T3 and A-1108-99T3 are NJBUS's appeals from those matters.) We consolidated the four appeals. Although the RA considered itself a respondent and did not file a notice of appeal, we directed it to file an appellant's brief on all matters on which it opposed the BPU's orders. We granted PSE&G's motion to accelerate the appeal.



We first consider Co-Steel's contention that the BPU's order, imposing stranded cost charges on it, was an unconstitutional impairment of its special ten-year contract with PSE&G from 1995 through 2005. Co-Steel claims that the order allows PSE&G to impose an "exit fee" on Co-Steel after the contract term expires, which in effect increases the agreed price of electricity during the contract term. In addition to constitutional considerations, Co-Steel says that principles of equity and estoppel should preclude PSE&G from imposing stranded cost charges because it relied on the contract in deciding to remain in New Jersey rather than moving its operations to Kentucky, where power costs were less expensive, and also by investing $37 million in the Perth Amboy plant. In the alternative, Co-Steel argues that even if we allow imposition of stranded cost charges, the BPU incorrectly applied the Act to its contract in three ways: (1) the BPU should have applied the rate reduction to all of its electricity consumption rather than to "block 1" only; (2) the rate reduction scheduled for August 2002 should reduce rates by 10% from their 1997 level not 13.9% from their 1999 level; and (3) the August 1999 rate reduction should reduce rates by 5% from their 1997, not 1999, level, a point which all appellants raise and which we consider separately.

The United States Constitution, art. I, § 10, provides that "[n]o State shall . . . pass any . . . Law impairing the Obligation of Contracts . . . . " Our New Jersey Constitution, art. IV, § 7, ¶ 3, has a parallel prohibition. Despite the difference in language, the federal and state Contract Clauses are applied coextensively and provide the same protection. Fidelity Union Trust Co. v. New Jersey Highway Auth., 85 N.J. 277, 299-300, appeal dismissed, 454 U.S. 804, 102 S. Ct. 76, 70 L. Ed. 2d 73 (1981).

The prohibition against impairment of contracts under the federal and state constitutions is not absolute. It "must be accommodated to the inherent police power of the states to safeguard the vital interests of their residents." In re Recycling & Salvage Corp., 246 N.J. Super. 79, 100 (App. Div. 1991). "The contract clause does not deprive the states of their power to adopt general regulatory measures even if those regulatory measures result in the impairment or destruction of private contracts." Ibid.

Our federal and state courts apply a three-prong test to determine whether legislation has unconstitutionally impaired a contract: they ask (1) has it substantially impaired a contractual relationship? (2) if so, does it have a significant and legitimate public purpose? and (3) is it based on reasonable conditions and reasonably related to appropriate governmental objectives? State Farm Mut. Auto. Ins. Co. v. State, 124 N.J. 32, 64 (1991).

In determining whether a contract impairment is substantial, courts consider whether the industry has been regulated in the past. Allied Structural Steel Co. v. Spannaus, 438 U.S. 234, 242 n.13, 98 S. Ct. 2716, 2721 n.13, 57 L. Ed. 2d 727, 735 n.13 (1978) ("When he purchased into an enterprise already regulated in the particular to which he now objects," he purchased subject to further legislation upon the same topic). On this first prong of the test, courts may also consider whether one of the parties reasonably relied on the contractual terms and whether the legislation was an unexpected modification of those terms. Nieves v. Hess Oil Virgin Islands Corp., 819 F.2d 1237, 1247 (3d Cir.), cert. denied, 484 U.S. 963, 108 S. Ct. 452, 98 L.Ed. 2d 392 (1987). For example, in Energy Reserves Group, Inc. v. Kansas Power & Light Co., 459 U.S. 400, 416, 103 S. Ct. 697, 707, 74 L. Ed. 2d 569, 583-84 (1983), the Court said that the natural gas contracts at issue "expressly recognize the existence of extensive regulation by providing that any contractual terms are subject to relevant present and future state and federal law," and could be interpreted "to incorporate all future state price regulation. . . ." At the very least, the Court said, the provision suggested that the gas company "knew its contractual rights were subject to alteration by state price regulation." Id. at 416, 103 S. Ct. at 707, 74 L. Ed. 2d at 584. As to the second and third prongs of the test, the legitimacy and reasonableness of legislation, the courts generally defer to legislative judgment, unless the State itself is a contracting party. Id. at 412-13, 103 S. Ct. at 705, 74 L. Ed. 2d at 581 (holding that a state statute regulating the price of natural gas did not violate the contract clause even if it did impair an energy company's contract with a public utility).

Here, respondents BPU, PSE&G, and RA counter Co-Steel's contract impairment argument by asserting that Co-Steel fails to satisfy the first prong of the test because the Act and the BPU restructuring order did not impair its contract; in fact, the end result was lower rates than provided for under the contract. The ten-year service agreement between Co-Steel and PSE&G was approved by the BPU on November 17, 1995, with the new rate effective retroactive to April 1, 1995. On July 24, 1995 a stipulation signed by the parties, the Attorney General (for the BPU), and the RA modified the agreement, specifically with reference to the Experimental Hourly Energy Pricing Tariff (EHEP) service offered to Co-Steel. The stipulation also refers to a July 1995 agreement with the New Jersey Treasury for a lower tax rate on the energy purchased under the contract.

The agreement between Co-Steel and PSE&G articulates the motivations of the parties: Co-Steel would forego closing its steel plant in Perth Amboy and moving its operations out of state, and would invest at least $37 million in improvements to its Perth Amboy plant between 1995 and 1999 in consideration for the special discounted pricing that PSE&G offered.

Under the agreement, electric services to Co-Steel would be priced in two blocks: the first 13 million kWh (block 1), which accounts for about one-third of Co-Steel's annual electricity consumption, would be billed monthly "at prices, terms, and conditions identical to PSE&G's then effective Rate Schedule High Tension Service (HTS)," that is, whatever the HTS tariff rate was at a particular time. Anything over 13 million kWh (block 2) would be billed at PSE&G's "marginal energy cost" (the cost of the electric utilities that make up the "PJM" power pool ÄÄ Pennsylvania, New Jersey, Maryland, and Delaware). Block 2 usage is governed by the EHEP service agreement, under which Co-Steel, the only customer under this service, would receive a discounted rate, with the cost of energy "vary[ing] hourly with changes in Public Service's marginal energy cost." According to Vincent Dimiceli, controller of Co-Steel, the effect of this "interruptible service" contract was to reduce its cost of electricity from an average of 5.9 cents per kWh to an average of 4.2 cents per kWh. The contract is silent as to what might occur when the contract term expired in 2005.

In the BPU order of August 24, 1999 the Commissioner ruled that, under the Act, N.J.S.A. 48:3-60, -61, and -67, HTS customers, along with all other electric public utility customers (except eligible on-site generator customers, N.J.S.A. 48:3-77), were subject to nonbypassable stranded cost charges (MTC, TBC, and SBC). At the same time, HTS customers would also receive rate reductions totaling 13.9% by August 1, 2002, and those reductions were, in part, due to securitization of the stranded cost charges. However, since Co-Steel's block 2 usage was governed by the special EHEP contract, it would be unaffected by the BPU order. The BPU refused to exempt Co-Steel from imposition of stranded cost charges, which could continue up to fifteen years after transition bonds are issued, well beyond the expiration of Co-Steel's contract.

According to Co-Steel, before the contract went into effect, its annual electric bill was $24 million, and under the contract the annual bill was lowered to $18 million. Co-Steel admits that, despite the imposition of surcharges on its HTS consumption, its block 1 costs would decrease under the BPU order due to the rate reductions applied to HTS customers. It also acknowledges that its block 2 rates are unaffected by the Act. Thus, the overall effect of the order will be "either neutral or . . . a slight decrease." However, Co-Steel believes that after the contract expires, when the mandatory rate reductions are no longer in effect, the transition charges authorized by the BPU order will allow PSE&G to collect between $4.5 and $6 million per year for ten or more years beyond the contract term. N.J.S.A. 48:3-61(i) (MTC charges may be imposed for up to eight years); N.J.S.A. 48:3-62(d)(1) (TBC charges may be imposed for up to fifteen years).

Thus, Co-Steel appears to admit that during the term of the contract the Act, as applied by the BPU order, will not impair its contract, but will in fact enhance it. Not until after the contract expires, will Co-Steel have considerable charges which it allegedly did not anticipate when negotiating the terms of the contract.

We conclude that the contract impairment argument is undermined by Co-Steel's failure to include contingencies for post-contract charges even though its own controller, Dimiceli, acknowledged that at the time he was negotiating the contract, in the fall of 1994, he was "generally aware that electric industry deregulation was somewhere on the horizon and that it might occur to one degree or another in the succeeding few years"; he believed that "there was a good chance [that competition] would arrive sometime during the ten-year term of our contract."

Co-Steel's argument is also undermined by two provisions of the agreement which allow for unilateral changes in its terms:

7. Taxes, Assessments or Other Charges: In the event that PSE&G incurs any taxes, assessments of or other charges in connection with the services to be provided hereunder, which were not applicable at the time of entering into this Agreement, including any increase in the Gross Receipts and Franchise Unit Tax, such taxes, assessments or other charges shall be passed through to Raritan as an increase in PSE&G's costs of providing service hereunder . . . .


9. Laws, Regulations, Orders, Approvals and Permits:

This Agreement is made subject to present and future local, state and federal laws and to the regulations or orders of any local, state or federal regulatory authority having jurisdiction over the matters set forth herein . . . .

As in Energy Reserves, 459 U.S. at 416, 103 S. Ct. at 707, 74 L. Ed. 2d at 584, the express language of paragraph nine of the agreement suggests that Co-Steel knew that its contractual rights were subject to alteration by state legislation. Thus, Co-Steel cannot have reasonably relied on the immutability of the agreement.

Co-Steel tries to distinguish the types of charges allowed under paragraph seven of the agreement and those imposed by the Act. It says that whereas paragraph seven allows PSE&G to "pass through" to Co-Steel any "taxes, assessments of or other charges [incurred by PSE&G] in connection with the services to be provided . . . as an increase in PSEG's costs of providing service," stranded cost charges are "amounts collected by PSE&G for the benefit of its shareholders" and incurred before the contract was negotiated; thus, they do not represent an increase in the cost of providing service during the term of the contract. Although such semantic distinctions may be true and have a certain allure, they do not alter the fact that the Legislature has mandated that stranded cost charges be passed along to customers as a cost of service. N.J.S.A. 48:3-60, -61, and -67. Thus, such charges are covered under the plain language of paragraph seven.

We conclude that Co-Steel's contract has not been substantially impaired but even if Co-Steel could satisfy this first prong of the test, it fails the second and third prongs. Co-Steel concedes that there is a legitimate purpose behind the collection of stranded costs by utilities and recognizes the legislative policy stated in the Act: to "[p]rovide for a smooth transition from a regulated to a competitive power supply marketplace" and to "maintain the financial integrity of the electric public utility through the transition to competition. . . ." N.J.S.A. 48:3-50(a)(12) and (c)(4).

However, Co-Steel contends that the imposition of stranded cost charges on it was not reasonable, and that we should not defer to the BPU's judgment because the State is a party to the contract. Although the BPU approved the contract and the Attorney General signed the 1995 stipulation on modifications to the contract, the real parties to the contract are PSE&G and Co-Steel. Deference must be accorded the legislative judgment and BPU's judgment concerning interpretation of the Act. Energy Reserves, 459 U.S. at 412-13, 103 S. Ct. at 705, 74 L. Ed. 2d at 581; New Jersey Guild of Hearing Aid Dispensers v. Long, 75 N.J. 544, 575 (1978).

Co-Steel argues that the stranded cost charges are a devastating burden for it but because they represent only a tiny fraction of the total to be collected by PSE&G, their loss would jeopardize neither PSE&G nor electric utility competition. The BPU responds by saying there is no justification for treating Co-Steel differently from all other customers: PSE&G will continue to provide distribution, transmission, and customer services after expiration of the contract, and Co-Steel should be obligated to pay its share of providing those services and its share of the stranded costs charges, which but for the Act would have been recovered in PSE&G's rates on a continuing basis. We also recognize that the nonbypassable stranded cost charges are not exit fees assessed only to customers who leave the utility but rather are imposed on all customers, whether or not they choose another energy supplier.

We think it unreasonable to treat Co-Steel differently from other PSE&G customers when its contract does not specifically call for any special post-contract treatment. It now is receiving the benefit of reduced rates through the contract, certain tax relief from the State, and the rate reductions resulting from the Act. When the contract expires, if it remains in New Jersey, it may also receive benefits from competition among electricity suppliers. We conclude it reasonable that Co-Steel bear its share of the stranded cost charges that are an integral part of the legislative deregulation scheme.

Co-Steel also argues that equitable principles should preclude imposition of these charges since it detrimentally relied on its contract when deciding to remain in New Jersey and invested $37 million in improvements to its Perth Amboy plant. But Co-Steel was aware that deregulation was literally "around the corner" and would most likely occur during the term of the contract. In fact, according to Dimiceli, Co-Steel was looking forward to "tak[ing] advantage of open competition after the contract expired." He saw the contract as a "trade-off": Co-Steel "would lock into a favorable electric rate for ten years, but in exchange we would be giving up the opportunity to participate in any competitive market for electricity that might develop before the end of our contract term." Co-Steel appears to want a "double bite," the favorable contract rate and the advantages of competition, but none of the associated costs of deregulation. The equities do not favor Co-Steel under these circumstances. Their reliance was not so much detrimental as it was shrewd.

Co-Steel's alternative argument addresses three specific aspects of the BPU order it contends were error. First, Co-Steel asserts that the rate reduction mandated by the Act should be applied to all of its usage, not just block 1 HTS usage because (1) it is unfair to impose on it the full burden of stranded cost charges but allow it only half the rate decrease granted other customers, and (2) N.J.S.A. 48:3-52(d)(1) mandates rate reductions for each "customer class," a category into which Co-Steel must, by logic, fall.

N.J.S.A. 48:3-52(d)(1) provides:

During a term to be fixed by the board, each electric public utility shall reduce its aggregate level of rates for each customer class, including any surcharges assessed pursuant to this act, by a percentage to be approved by the board, which shall be at least 10 percent relative to the aggregate level of bundled rates in effect as of April 30, 1997, subject to the provisions of paragraph (2) of this subsection.

The Act does not define "customer class."

In its August 24, 1999 Final Decision, the BPU determined that the rate reduction and the stranded cost charges applied to Co-Steel's HTS block 1 usage, but that the Act would not affect its block 2 usage, which was governed by the EHEP contract. In its October 19, 1999 denial of Co-Steel's motion for reconsideration, the BPU clarified that the MTC, TBC, and SBC stranded cost charges would not be imposed on the block 2 discounted rate, and that the discounted rate would not be affected by the Act. It was only the HTS tariff usage (block 1) that would be affected by both the stranded cost charges and the rate reductions mandated by the Act, because that tariff was not "designed . . . to insulate customers from future additional charges relating to the provision of service." The BPU's decision was grounded solidly on holding the parties to the terms of Co-Steel's contract with PSE&G.

As to the definition of "customer class," the BPU interpreted it to mean "customers served under fixed tariffs, not customers that have made separate arrangements to receive service at heavily discounted rates." Although Co-Steel makes a strong argument that it should be considered as part of a customer class, it ignores the fact that it bargained for a special rate that literally put it into a class by itself: it is the only PSE&G customer receiving a discounted rate under an EHEP service agreement.

The interpretation of "customer class" announced by the BPU, the administrative agency charged with the enforcement of the Act, should be given great weight by the court. New Jersey Guild of Hearing Aid Dispensers, 75 N.J. at 575; In re South Jersey Gas Co., 226 N.J. Super. 327, 333 (App. Div. 1988), aff'd, 116 N.J. 251 (1989). However, even without reaching the validity of that interpretation, the underlying principle of enforcing a contract as written was a valid basis for the BPU's decision.

Co-Steel next argues that, under N.J.S.A. 48:3-52(d)(1) *fn1 , it is entitled to a 10% reduction from its April 30, 1997, rates rather than a 13.9% reduction from current rates by August 1, 2002 as ordered by the BPU, because the BPU's decision was premised on the 3.9% increase experienced by most PSE&G customers in 1998, whereas Co-Steel's increase during that period was 9%.

N.J.S.A. 48:3-52(d)(1), quoted above, mandates a rate reduction that is at least 10% below the April 30, 1997 rates, to be implemented "[d]uring a term to be fixed by the board." The following subsection of the statute allows the BPU to "set a term for an electric public utility to phase in a rate reduction of ten percent or more during the first 36 months after the starting date for the implementation of retail choice" (August 1, 1999) and requires that the rate reduction on August 1, 1999, be at least 5%. N.J.S.A. 48:3-52(d)(2). The statute allows the BPU to order a rate reduction greater than 10% "if it determines that such reductions are necessary in order to achieve just and reasonable rates." N.J.S.A. 48:3-52(e).

In its Final Decision, the BPU ordered cumulative rate reductions that would equal 5% effective August 1, 1999, 7% "on or about" January 1, 2000, 9% effective August 1, 2001 and 13.9% effective August 1, 2002. The BPU explained this decision in addressing Co-Steel's arguments in its motion for reconsideration. It said that whether or not Co-Steel should receive only a 13.9% reduction on August 1, 2002, will depend to a large extent on the particular tariff design to be developed for Co-Steel as an EHEP customer in 2002. Co-Steel's argument is based on the fact that because DSAF charges are recovered on a volumetric basis, its DSAF increases in 1998 were higher than those of other customers. Co-Steel thus asserts that it should experience, due to those earlier larger DSAF increases, a greater reduction in rates than those customers that may have experienced a DSAF increase closer to the overall average of 3.9 percent. The Board agrees that this issue should be looked into at the time the appropriate tariff designs covering these future rate reductions are completed and approved by the Board. Therefore, before the Board gives its final approval to rate reduction to be effective on August 1, 2002, it will consider the appropriate rate design for all of its customers including Co-Steel. In doing so, the Board will be considering any arguments Co-Steel may wish to present at that time. [(emphasis added).]

Thus, the BPU acknowledges that Co-Steel's 1998 increases were greater than those of the average PSE&G customer, which may indicate the need for a reduction greater than 13.9% in 2002. The BPU merely asserts, as does PSE&G, that the issue is not ripe for adjudication at this point.

N.J.S.A. 48:3-52(d) gives the BPU the discretion to determine the amount of the rate reductions and the term during which they are phased in, as long as the August 1999 reduction is at least 5%, the total rate reduction is at least 10% over the 1997 level, and the phase-in period is accomplished within three years of August 1999. The BPU has acknowledged that for Co-Steel this may mean a greater than 13.9% increase by 2002, and that it will entertain Co-Steel's arguments on the issue before ordering final approval on the 2002 increase. We see no dispute to resolve at this point.

Finally, Co-Steel contends that the 1999 rate reduction should be 5% from 1997 rates rather than 5% from 1999 rates. Appellants RA and NJBUS join in this argument. As discussed, N.J.S.A. 48:3-52(d)(1) mandates a rate reduction of at least 10% "relative to the aggregate level of bundled rates in effect as of April 30, 1997. . . ." The next subsection, N.J.S.A. 48:3-52(d)(2), gives the BPU discretion in phasing in the total reductions over the next three years, but it does require that utilities reduce rates "by no less than five percent." This subsection does not mention relative to what date the 5% decrease is to be compared. Because there was a 3.9% rate increase in 1998, a 5% reduction from current (1999) rates would be only a 1.1% reduction from 1997 rates.

Appellants argue that section (d)(2) must be read in conjunction with section (d)(1) to make sense; there was no need to repeat the specification about "relative to 1997 rates" when that language was already present in (d)(1). Respondents argue that the clear language of the statute must control; the Legislature knew how to include the specification "relative to 1997" when it wanted to do so, its failure to do so in section (d)(2) must have been intentional. In support of their position, appellants refer to the language of the BPU's April 30, 1997 Final Report when recommending "a near term rate reduction on the order of 5-10%":

In response to concerns that these targeted rate reductions may be eroded by subsequent upward rate adjustments between now and the date of retail competition, we emphasize that the targeted rate reductions must be in comparison to the current level of rates as of the date of this report. [(emphasis added).]

Indeed, the rate reduction in N.J.S.A. 48:3-52(d)(1) is from the 1997 level and thus complies with that recommendation. The traditional rubrics and principles of statutory construction could lead to nothing more than our second-guessing the Legislature's intent. "The various canons or maxims of statutory construction are tools not icons." Wildwood Storage Center, Inc. v. Mayor & Council of the City of Wildwood, 260 N.J. Super. 464, 471 (App. Div. 1992). Common sense leads to the conclusion that the BPU's schedule of rate reductions is a reasonable interpretation of the statute. "Statutory interpretations should turn on the breadth of the legislative objectives and the common sense of the situation." Cty. of Camden v. S.J. Port Corp., 312 N.J. Super. 387, 396 (App. Div.), certif. denied, 157 N.J. 542 (1998). Also, "[o]ur task is to harmonize the individual sections and read the statute in the way that is most consistent with the overall legislative intent." Fiore v Consol. Freightways, 140 N.J. 452, 466 (1995).

Appellants are in essence saying that, of the total 13.9% in rate reductions, the 1999 reduction should be 8.9%, with the remaining 5% to come by 2002. Thus the greater part of the total reductions would be implemented immediately rather than spread more evenly over the course of three years. One of the primary concerns of the Act is the financial integrity of the utilities. N.J.S.A. 48:3-50(c)(4). The decision to spread the rate reductions out more evenly over the course of three years was consistent with that goal. Further undermining the argument to the contrary is the RA's proposal in Stipulation II, dated March 29, 1999, that the August 1, 1999, 5% rate reduction be from current (1999) rates.



Appellants RA and NJBUS contend that the regulatory proceedings involved numerous procedural irregularities which violated federal and state due process protections, principles of fundamental fairness, the Administrative Procedure Act, N.J.S.A. 52:14B-1 to -15 (APA), the BPU's own regulations, and the Act itself. In particular, they point to the BPU's refusal to reopen the record after passage of the Act despite substantial changes in the legal standards on the basis of which the record had been developed. The RA also points to adoption of aspects of Stipulation I which had not been raised previously, without first giving the non-settling parties an opportunity to address these issues in an evidentiary hearing. The RA alleges that the BPU, in its Final Decision, relied on an auditors' report, a document not in evidence, in arriving at a sum quantifying the amount of PSE&G's stranded costs. As to the securitization decision, the RA contends that the BPU violated the APA by failing to conduct hearings on PSE&G's financing petition and NJBUS contends that the BPU violated its own regulations when it excluded NJBUS from intervening in the securitization proceedings.

The Public Utilities Act, N.J.S.A. 48:2-2 to -91, gives this court jurisdiction to review any order of the BPU and to set all or part of an order aside "when it clearly appears that there was no evidence before the board to support the same reasonably." N.J.S.A. 48:2-46. However, the Public Utilities Act specifically prohibits this court from reversing BPU orders for minor procedural irregularities:

No order shall be set aside in whole or in part for any irregularity or informality in the proceedings of the board unless the irregularity or informality tends to defeat or impair the substantial right or interest of the appellant. [N.J.S.A. 48:2-46.]

This provision attempts to reconcile the Legislature's "sweeping grant of power" to the BPU to regulate utilities, In re Alleged Violations of Law By Valley Road Sewerage Co., 154 N.J. 224, 235 (1998), with constitutional due process guarantees and principles of fundamental fairness.

The Fourteenth Amendment of the United States Constitution provides that no state shall "deprive any person of life, liberty, or property, without due process of law." Article I, paragraph 1 of the New Jersey Constitution protects similar interests. Greenberg v. Kimmelman, 99 N.J. 552, 568 (1985). "Due process is a flexible concept that calls for such procedural protections as fairness demands," the essential components of which are notice and an opportunity to be heard. Mettinger v. Globe Slicing Mach. Co. Inc., 153 N.J. 371, 389 (1998).

Where constitutional protections do not adequately safeguard an important interest, principles of fundamental fairness come into play. State v. P.Z., 152 N.J. 86, 117 (1997). New Jersey's doctrine of fundamental fairness protects against "unjust and arbitrary governmental actions, and specifically against governmental procedures that tend to operate arbitrarily." John Doe v. Poritz, 142 N.J. 1, 108 (1995). This is a doctrine sparingly applied but available, "where the interests involved are especially compelling." Ibid.

In assessing the procedural adequacy of administrative proceedings, we start with the proposition that "[a]dministrative agencies enjoy a great deal of flexibility in selecting the proceedings most suitable to achieving their regulatory aims." Bally Mfg. Corp. v. New Jersey Casino Control Comm'n, 85 N.J. 325, 338, appeal dismissed, 454 U.S. 804, 102 S. Ct. 77, 70 L. Ed. 2d 74 (1981). For example, administrative agencies have the discretion to decide whether a case is to be classified as "contested," ibid. (citing N.J.S.A. 52:14F-7(a) of the APA), whether to reopen a hearing to admit further evidence before the entry of a final decision, In re Kallen, 92 N.J. 14, 24 (1983), and whether to "look[] beyond the four corners of the record" in making a final determination. In re Shore Hills Water Co., 101 N.J. Super. 214, 222 (App. Div. 1968).

"Normally courts defer to the procedure chosen by the agency in discharging its statutory duty," subject, of course, to the requirements of due process and the APA. In re Request for Solid Waste Util. Customer Lists, 106 N.J. 508, 519 (1987). The agency has discretion "to select those procedures most appropriate to enable the agency to implement legislative policy." Texter v. Department of Human Services, 88 N.J. 376, 385 (1982). Thus, the lines between rulemaking and formal adjudication sometimes become blurred; in fact, informal action constitutes "the bulk" of administrative action. In re Request for Solid Waste Util., 106 N.J. at 518.

In rate-setting cases, where the administrative agency must balance competing consumer and utility interests, courts allow the agency "the fullest exercise of administrative discretion." In re Rockland Elec. Co., 231 N.J. Super. 478, 494-95 (App. Div.), certif. denied, 117 N.J. 129 (1989). Unless there is a fundamental deficiency in procedure, exercises of administrative judgment will be affirmed as long as they are based on sufficient credible evidence and do not result in arbitrary or unreasonable consequences. In re N.J. Bell Tel. Co., 291 N.J. Super. 77, 89-91 (App. Div. 1996).


From late 1997 to 1999, when the unbundling, stranded costs, and restructuring proceedings were conducted, the standards which the parties relied on were the BPU's recommendations to the Legislature in its 1997 Final Report. The OAL proceedings for all four utilities were, in part, legislative-type hearings in the sense that they gathered evidence on generic issues affecting the deregulation process as a whole. As the hearings proceeded, the BPU's staff drafted proposed legislation, which it shared with the parties, and which was considered by the Legislature. The final draft of the deregulation bill was introduced on January 25, 1999, was passed by both the Assembly and the Senate three days later, and was approved on February 9, 1999 effective immediately. There were no traditional legislative hearings.

The Act mandated that rate reductions and competition begin by no later than August 1, 1999 less than six months after the Act went into effect. N.J.S.A. 48:3-53(a). To expedite the process of preparing for competition, the Act allowed the BPU to rely on proceedings dating as far back as April 1, 1997 when taking regulatory action:

This act shall take effect immediately, except that, to the extent not already provided for by existing law, the authority of the board to order rate unbundling filings, restructuring filings, and stranded cost filings, perform audits of utility competitive services and take such other regulatory actions, including, but not limited to, the holding of hearings, providing of notice and opportunity for comment, the issuance of orders, and the establishment of standards, including auction standards adopted for application to an electric public utility that is executing a divestiture plan, and to take such other anticipatory regulatory action as it deems necessary to fulfill the purposes or requirements of this act shall apply retroactively to April 1, 1997 provided that the board shall take such actions as may be necessary, if any, to ensure that the requirements of this act are met in all regulatory actions related to this act which were commenced prior to its enactment. [N.J.S.A. 48:3-98 (emphasis added).]

There is accuracy to PSE&G's characterization of the administrative proceedings and the development of the legislation as being on a "parallel track." Appellants were aware of this because they were active participants in the process, as were over thirty other intervenors from the commercial, public interest, and utility sectors.

In the BPU's Final Decision, it rejected the contention "of some of the parties" that the record should be reopened, basing its decision on its March 25, 1999 order denying a motion by the Mid-Atlantic Power Supply Association (MAPSA) to reopen the record after passage of the Act. There, the BPU said that the new legislation was not in and of itself a "sufficient basis to reopen the record." It continued:

The record in this case clearly contemplated the enactment of comprehensive electric deregulation legislation. The hearings at the OAL were intended to develop an extensive record with respect to factual rate unbundling and stranded costs issues, while the restructuring plan hearings before the Board were intended to develop an extensive record on the more generic restructuring policy issues, all of which would then be used by the Board to develop a final order for each electric utility consistent with the legislative requirements, including the schedule laid out by the Legislature for the commencement of competition.


Based on our review of the Act and the record below, we find that the parties have had an extensive opportunity to litigate all relevant issues through discovery, the filing of testimony, many days of evidentiary hearings, cross-examination, initial and reply briefs and Exceptions and Reply Exceptions to the Initial Decision. The Board disagrees with and HEREBY REJECTS the generalized contentions of MAPSA, the Ratepayer Advocate, ACE, and NJBUS that the record needs to be reopened to comply with the requirements of the Act and/or due process.

The RA supported MAPSA's motion, but on grounds other than the claim that passage of the Act changed the standards on which the matter was litigated.

The RA now contends that the Act made two significant changes to the Final Report, necessitating taking additional evidence as permitted under N.J.S.A. 48:3-98. The changes they point to are: (1) the Act resulted in a standard for stranded cost eligibility for post-1992 capital additions more favorable to utilities than the standard under the Final Report; and (2) the Act allowed a utility to securitize up to 75% of its generation-related stranded costs, whereas the BPU's September 19, 1997 order limited securitization to 50% of the BPU-determined stranded cost level.

NJBUS contends that the Act established new standards for determining stranded costs and shopping credits, concepts that did not exist in the Public Utilities Law prior to passage of the Act. NJBUS also contends the BPU violated its own regulations when it denied MAPSA's motion to reopen the record, because N.J.A.C. 14:1-8.4 allows for reopening if there have been any "material changes of fact or law" since the last hearing.

At the outset, we recognize that the BPU's Final Decision was not based strictly on the standards announced in the Final Report and the record developed based on those standards, but on an agreement (Stipulation I), between some of the parties to which the appellants had ample opportunity to respond through comments. None of the changes referred to by the RA and NJBUS came as a surprise to them. Although stranded costs and shopping credits were not a part of the body of earlier Public Utilities Law, they were concepts which the parties had been aware of throughout these proceedings to the Final Report stage, when the deregulation legislation was being drafted and as the administrative hearings were being held.

The first change referred to by the RA, criteria for stranded cost eligibility of post-1992 capital additions, made it easier for PSE&G to meet the eligibility requirements. See N.J.S.A. 48:3-61(c). Thus, the standard on which the administrative proceedings were based was less favorable to PSE&G. At the OAL hearings, under the earlier, more difficult standard, the RA contested PSE&G's requested stranded cost recovery of $1.4 billion attributable to capital additions; the BPU staff, after reviewing the independent auditor's report, supported inclusion of many but not all of the fossil and nuclear projects for which PSE&G sought stranded cost recovery. The ALJ agreed with the BPU staff that PSE&G had substantially justified inclusion of the bulk of its post-1992 capital additions and recommended that the BPU recognize their inclusions for stranded cost calculation purposes. In its Final Decision, the BPU accepted the stranded cost figure agreed to in Stipulation I.

The RA does not clarify how reopening the record to take evidence under the new, more lenient standard would help utility customers, who received the benefit of the more rigorous standard at the OAL hearings. Indeed, it seems more likely to hurt them. Nor does NJBUS explain how its cause would be aided by reopening the record on the Act's new standards for determining stranded costs and shopping credits.

The second change referred to by the RA, the right to securitize up to 75% of stranded costs rather than 50%, is really a substantive challenge to the statute rather than a due process argument. The RA explains how securitizing stranded costs precludes a "true-up" of the recovery amount to actual market costs because the transition bond order is legally irrevocable, but does not explain how taking evidence on this new securitization cap could hope to change the Final Decision. Indeed, according to the BPU's theory, it permitted PSE&G to securitize only 48% of its stranded costs. Thus hearing evidence on the new cap would have had no effect on the Final Decision.

Finally, NJBUS contends that the BPU violated N.J.A.C. 14:1-8.4 by failing to grant MAPSA's motion to reopen the record. That regulation describes the method for requesting that a hearing be reopened and gives the BPU the discretion to reopen hearings if it has "reason to believe that conditions of fact or of law have so changed as to require, or that the public interest requires, the reopening of such hearing. . . ." N.J.A.C. 14:1-8.4(b). The BPU soundly exercised its discretion when it determined that the passage of the Act did not raise any new issues uncontemplated during the course of the administrative proceedings. NJBUS has not demonstrated how the BPU abused its discretion in denying MAPSA's motion to reopen.


The RA contends that Stipulation I raised three issues not addressed during the hearings: (1) formation of an unregulated affiliate (GENCO) and immediate transfer of PSE&G's generating facilities to GENCO at book value; (2) a four-year transition period with rate reductions lasting only four years; and (3) the use of deferred accounting to achieve statutory rate reductions. The RA acknowledges that it had an opportunity to file comments on Stipulation I, but says that BPU had nothing in the record to review before adopting these newly-raised proposals and needed evidentiary hearings on them.

As a preliminary matter, since the RA had notice and an opportunity to be heard on the issues raised in Stipulation I, it received the essential requirements of due process. Mettinger, 153 N.J. at 389. The BPU has the discretion to determine what kind of procedure was most appropriate to further legislative policy, Texter, 88 N.J. at 385, and it determined that proceeding on the basis of the record already before it, in addition to the parties' comments on the stipulations, was appropriate. Agencies are well within their authority to adopt stipulations as fact-finding tools, as long as they evaluate the stipulations and the parties have had an opportunity to argue against them. Petition of Pub. Ser. Elec. & Gas, 304 N.J. Super. 247, 268-72 (App. Div.), certif. denied, 152 N.J. 12 (1997). Furthermore, New Jersey has a strong public policy in favor of settlements. Dept. of Pub. Advocate, Div. of Rate Counsel v. New Jersey Bd. of Pub. Util., 206 N.J. Super. 523, 528 (App. Div. 1985). Here, although Stipulation I introduced some new proposals, it did not introduce new concepts which had never been considered by the parties during the proceedings.


The Act allows for "the transfer of electric public utility assets from an electric public utility to a related competitive business segment of that electric public utility or of a public utility holding company. . . ." N.J.S.A. 48:3-55(d). N.J.S.A. 48:3-59(a) states that the BPU may require a utility to functionally separate its generation assets transferred to a holding company or a related competitive business segment, or it may order divestiture to an unaffiliated entity "if it finds that concentration or location of generation facilities results in market control that would adversely effect the formation of a competitive generation marketplace." Statement attached to Assembly Bill A-16, P.L. 1999, c. 23, comment on section 11. Complete divestiture has always been considered an option, and according to the BPU, the three other electric public utilities have chosen to divest themselves of their generating assets through sales to unaffiliated entities.

PSE&G's original plan was to transfer its generating facilities to a separate unregulated entity after a seven-year transition period. This was the proposal which the ALJ discussed in his Initial Decision. There was, however, testimony on alternatives: for example, a witness on behalf of IEPNJ faulted PSE&G for separation of its generating facilities after, rather than at the beginning of, the transition period and a witness on behalf of the RA testified that complete divestiture was the best option.

During the settlement process, and after passage of the Act, PSE&G agreed to an immediate transfer of its generating facilities and assets to GENCO. In its Final Decision the BPU approved of the immediate transfer, saying that it was "amply supported by the record in this proceeding." The BPU found that the reason for PSE&G's delay of the transfer ÄÄ "a liquid and visible capacity market did not yet exist in the PJM control area" ÄÄ no longer existed and thus the conditions "support the immediate transfer of the assets." The BPU noted that PSE&G proposed the immediate transfer in response to the "concerns voiced by a number of parties during these proceedings," adding that during the hearings several of the parties testified that "structural separation of generation-related assets into a separate corporate entity was necessary to provide adequate protections."

Thus, the various ways for an electric utility to handle its generation facilities ÄÄ whether divestiture, transfer to an affiliate, or retention of generation facilities ÄÄ were present in the testimony during the hearings. Because of the parties' opportunity to comment on Stipulation I, and the statutory validity of such a transfer, there was nothing procedurally unfair about the immediate transfer without further hearings.


Under the Act, rate reductions must begin by August 1, 1999, N.J.S.A. 48:3-53(a), and be sustained for forty-eight months, or until July 31, 2003. N.J.S.A. 48:3-52(j). Although PSE&G originally proposed a seven-year transition period, Stipulation I proposed a four-year transition period ÄÄ from August 1, 1999, through July 31, 2003 ÄÄ during which rate reductions would be phased in. The RA and other parties to Stipulation II proposed a more extended period of rate reductions, with higher levels of reductions, which the BPU found relied upon "assumptions that are plainly incorrect."

PSE&G's period and rate of reductions comply with the Act. The RA's alternative was considered by the BPU, as were its comments on Stipulation I. The RA was not denied procedural due process in the matter and, in reality, is challenging the substance of the BPU's decision.


Stipulation I proposed that the actual costs related to the SBC (social programs, nuclear plant decommissioning, demand side management program, manufactured gas plant remediation, consumer education) and any fluctuation in the above-market costs of the Nonutility Generation Market Transition Charge (NTC) be subject to deferred accounting. Deferred accounting allows a regulated entity to defer on its books, rather than write off, certain expenses, based on a regulator's promise to allow recovery at a later date. The BPU accepted this deferred accounting procedure for SBC and NTC charges.

The reasonableness of the BPU's decision will be discussed in Issue V(D). For now we need only note that, under the Final Decision, PSE&G has been ordered to make the statutorily mandated reductions, and there is nothing in the Act to prohibit deferred accounting. In fact, under N.J.S.A. 48:3-57(b)(3), the BPU

may devise an alternative accounting or cost recovery process that permits an electric public utility . . . to provide basic generation service to its customers during the period that the electric public utility is providing for sustainable rate reductions . . . if the board determines that such process is necessary to mitigate the impacts of market price fluctuations and to sustain such rate reductions.

Thus, the BPU statutorily has the discretion to authorize such alternative accounting methods as it deems necessary. The Supreme Court has held that hearings are not needed on such discretionary accounting decisions. In re Jersey Central Power & Light Co., 85 N.J. 520, 528 (1981) (holding that the BPU acted within its discretion in accelerating amortization of electric utility's deferred energy account, which did not result in a rate increase, despite the lack of notice or hearings). Although traditional due process was not required for the deferred accounting decision, the RA did receive the essential requirements of notice and an opportunity to be heard when it was permitted to submit comments on Stipulation I.


The document in issue is "PSE&G Stranded Cost Calculations," dated November 6, 1998 which was commissioned by the BPU staff and prepared by the independent auditors, ICF. The circumstances which led to its preparation were as follows: On August 17, 1998 in his Initial Decision, the ALJ made various recommendations on stranded cost recovery adjustments but found it "impossible to determine a specific stranded cost amount for the Board's consideration" and advised it would be "most appropriate for the parties to confer on this issue and submit to the Board for its review a stranded cost figure that incorporates my findings and recommendations."

On September 23, 1998 the BPU staff convened a conference for that purpose. The parties could not agree on the quantification of stranded costs. The BPU staff then commissioned the ICF report. On October 2, 1998 the RA submitted its exceptions to the ALJ's Initial Decision, which included its preliminary calculation that the ALJ's decision would result in stranded costs totaling $3.407 billion. In PSE&G's exceptions, it noted that its calculation of stranded costs based on the ALJ's suggested adjustments totaled $3.7 billion. On October 30, 1998 the RA submitted its reply to PSE&G's exceptions, standing by its stranded cost calculation and noting that the BPU "may modify several of the ALJ's recommendations," rendering any quantification moot. For that and other reasons, the RA believed that any of the parties' "attempts to reduce the ALJ's decision into a discrete stranded cost figure is somewhat arbitrary and should not necessarily be relied upon by the Board." The ICF report offered three different calculations based on different inflation rates, arriving at stranded cost valuations of $2.485 billion, $2.949 billion, and $3.310 billion.

On November 18, 1998 the Attorney General's office sent the ICF report to the parties, including the RA and the BPU Commissioner. In the cover letter, the deputy attorney general stated that the stranded costs calculation "represents the best interpretation and quantification of the ALJ's Initial Decision" by ICF, but that the "quantification does not necessarily represent the position of the BPU staff." The letter also stated that the report was submitted "for your information." The DAG's letter did not specifically invite or preclude written comments. No responses were received.

In Stipulation I, PSE&G proposed stranded costs totaling $3.3 billion. In Stipulation II, the RA proposed stranded costs totaling $2.8 billion. The parties submitted written comments on the stipulations.

In its Final Decision, the BPU adopted the ALJ's decision as to adjustments for stranded costs and accepted "as reasonable" ICF's mid-range quantification of stranded costs based on the ALJ's decision, $2.949 billion, a compromise sum. However, the BPU made one minor modification to account for emission credits and lowered the figure to $2.94 billion for net-of-tax stranded costs.

In support of the contention that it was improper for the BPU to rely on the ICF report, because it was not formally admitted into evidence at the hearing, the RA cites In re Parlow, 192 N.J. Super. 247, 249 (App. Div. 1983). In Parlow we held that the Civil Service Commission improperly relied on an employee's service record, which was not admitted into evidence before the ALJ, in rejecting the ALJ's decision. We observed that there was no notice to the parties or opportunity for rebuttal. In response to Parlow, the BPU says that there is nothing improper about relying on the assistance of staff or consultants, citing for support In re Allegations of Violations of Law and Admin. Code by A. Fiore & Sons, Inc., 94 N.J.A.R.2d 175, 195-96 (EPE 1994), rev'd in part on other grounds, 96 N.J.A.R.2d 305 (EPE 1996). There the respondents objected to the ALJ directing the staff of the BPU to calculate penalty and refunds in accordance with his findings, after the close of the record. The Commissioner of the Department of Environmental Protection and Energy said that the "ALJ's directive is unobjectionable and, indeed, commonplace." The Staff did not engage in ex parte activity, but "merely performed a ministerial task at the direction of the ALJ."

Of course, preparation of the ICF report was more than a merely ministerial task. However, unlike in Parlow, the parties were given copies of the document and knew it was prepared precisely in order to help the BPU quantify PSE&G's stranded costs. Although written comments were not requested, nothing prevented the RA from responding to this critical report. The Final Decision was not entered until August 1999, ten months later, so there was ample time and opportunity to respond. In fact, the report most certainly was considered by the parties in arriving at their own calculations of stranded costs for their stipulations, which were prepared in March 1999, four months after the ICF report was sent to them.

Because the RA had notice of the ICF report and an opportunity to respond to it, we conclude that the BPU's reliance on the report was not a procedural irregularity sufficient to deny the RA due process. It was neither fundamentally unfair, nor rose to the level required under N.J.S.A. 48:2-46 for setting aside the order.


The RA contends that the BPU violated constitutional due process, the APA, and the Act by issuing a decision on securitization without conducting hearings because there were factual issues in dispute and the agency was acting in a quasi-judicial capacity. Relying on the 1998 stranded cost hearings was inappropriate, the RA says, because the 1999 securitization filing raised new issues not addressed therein. Even if hearings were not required, the RA urges it should have been given an opportunity to meet and rebut the expert analysis on which the BPU relied. Also the RA claims PSE&G made two important last-minute revisions to its financing petition to which the RA did not have an opportunity to respond.

Securitization concerns the structuring and pricing of transition bonds, which are used to reduce stranded costs. Statement on Assembly Bill A-16, comment on section 14. PSE&G filed its financing petition in June 1999, after the hearings on rate unbundling and stranded costs and the BPU's April 21, 1999 summary order, which included the BPU's determination that PSE&G could securitize up to $2.4 billion of its net-of-tax stranded costs. On August 11, 1999 the RA filed comments, raising thirteen issues, including the contention that evidentiary hearings should be held on the matter. On August 24, 1999 the BPU held a public meeting at which it rendered its oral decision that such hearings were not required. On that same day the BPU issued its final decision in the rate unbundling, stranded cost, and restructuring proceedings, which elaborated on its April 21, 1999 summary order.

PSE&G filed revisions to its financing petition on September 2 and 10, 1999. According to the BPU, it actually received a copy of the second revisions on September 9, the day before a public meeting on the matter was held. The BSCRO was entered on September 17, 1999.

The APA provides for hearings in contested cases, N.J.S.A. 52:14B-9(a), which it defines as a proceeding in which "the legal rights, duties, obligations, privileges, benefits or other legal relations of specific parties are required by constitutional right or by statute to be determined by an agency . . . ." N.J.S.A. 52:14B-2(b). The Act does not require evidentiary hearings to be held on BSCROs. N.J.S.A. 48:3-64. In fact, the section of the statute that deals with BSCROs provides that "all proceedings in connection with the determination of bondable stranded costs, transition bond charges and bondable stranded costs rate orders shall be exempt from the provisions of Title 48 [Public Utilities] of the Revised Statutes and any regulations promulgated thereunder." N.J.S.A. 48:3-64(f). N.J.S.A. 48:3-64(a) refers back to N.J.S.A. 48:3-62, the section on stranded cost recovery and transition bonds, which does not mention a hearing requirement. N.J.S.A. 48:3-64(a) does not refer back to N.J.S.A. 48:3-61, which requires hearings after the utility submits a stranded cost filing in order to establish a market transition charge. N.J.S.A. 48:3-61(c). After such hearings, the BPU must issue a stranded cost recovery order; but it may also issue a "successor order" setting forth the mechanism by which the utility will recover stranded costs. N.J.S.A. 48:3-61(c). The BPU persuasively characterizes the BSCRO at issue here as a successor order to its earlier restructuring order of April 21, 1999. Even if a hearing is not required under the Act or the APA, it may be required by constitutional right if there are "material disputed adjudicative facts" at issue. Frank v. Ivy Club, 120 N.J. 73, 98 (1990), cert. denied, 498 U.S. 1073, 111 S. Ct. 799, 112 L. Ed.2d 860 (1991) (emphasis added). To support its assertion that there were numerous material factual issues in dispute, the RA points to the extensive discovery conducted by the BPU and the RA and the issues it raised in its August 11, 1999 comments. However, those issues involved policy decisions, such as the percentage of stranded costs to securitize, whether to have an MTC tax approved as part of the BSCRO, and legal decisions, such as whether aspects of the petition violate the Act. Such quasi-legislative decision making does not require trial-type hearings. High Horizons Dev. Co. v. Department of Transp., 120 N.J. 40, 51 (1990). Furthermore, the establishment of an MTC tax was suggested by the RA in comments on Stipulation I. Most of the purely adjudicative facts had already been dealt with in the hearings held on unbundled rates, stranded costs, and restructuring; e.g., the amount of stranded costs which would be securitized.

In its September 17, 1999 decision on the RA's comments, the BPU stressed, as it does again here, that the RA did not submit an affidavit setting forth the specific facts demonstrating that there were genuine issues requiring an evidentiary hearing. See Frank, 120 N.J. at 99. The RA now points specifically to the "mechanics of recovery" of the MTC tax as a factual issue requiring evidentiary exploration. However, the factual question as to the amount of stranded costs and how much that figure would be when "grossed up" for taxes was decided in the stranded cost proceedings; at the securitization stage the question was one of methodology. This did not require trial-type hearings.

Although requisite due process is required, informal procedures may satisfy that requirement as long as the parties had "adequate notice, a chance to know opposing evidence, and to present evidence and argument in response." High Horizons, 120 N.J. at 53. Here, the RA had notice of PSE&G's financing petition, was given an opportunity to engage in discovery and comment on the petition, and to attend the public meeting on the petition. Although the MTC tax and the mechanics of its recovery may not have been addressed during the stranded cost hearings, the RA itself suggested the mechanism when commenting on Stipulation I, the BPU established the MTC tax in the Final Decision, and PSE&G included it in its financing petition, on which the RA commented. Thus, the essentials of due process were satisfied.

Even when adjudicative hearings are not required, agencies are not permitted to act on undisclosed evidence which parties have not had an opportunity to rebut. Ibid. The RA contends that the BPU adopted PSE&G's September 2 and 10, 1999 revisions without giving it an opportunity to respond. The September 2, 1999 attachment is a computation of ratepayer savings for the fifteen-year period of the transition bonds, and the September 10, 1999 attachment is a revision of supporting schedules, which affect rate reductions and the level of TBC and MTC tax charges over the course of fifteen years. The RA acknowledges it received a copy of the September 2 submission and had an opportunity to respond to the submission before the September 10 public meeting. However, as to the September 10 submission, even the BPU admits that there was no time for the RA to review and respond to it, although the BPU staff did have a chance to "consider it and reject it." Comparison of the September 10 submission and the attachment to the September 17, 1999 BSCRO supports the BPU's assertion that it did not rely on the September 10 submission or did not use the same figures as reflected in that submission. Since the BPU did not substantively consider the late submission, the RA cannot effectively complain that the agency acted on undisclosed evidence. We conclude that the BPU acted within its discretion by relying on the stranded cost hearings and the comment process in the securitization proceedings.


NJBUS contends that the BPU erred in rejecting its petition to intervene in the securitization proceedings. NJBUS claims its members have a significant stake in the outcome of the proceedings, their interest is markedly different from the interests of other parties, and they have considerable expertise and experience in utility regulation matters.

The standards for intervention in an administrative proceeding are governed by N.J.A.C. 1:1-16.3. Under that regulation, these factors are considered:

the nature and extent of the movant's interest in the outcome of the case, whether or not the movant's interest is sufficiently different from that of any party so as to add measurably and constructively to the scope of the case, the prospect of confusion or undue delay arising from the movant's inclusion, and other appropriate matters. [N.J.A.C. 1:1-16.3(a).]

The BPU denied NJBUS's and Co-Steel's motions to intervene in the securitization proceedings because it found that neither of the parties had satisfied the criteria of N.J.A.C. 1:1-16.3; specifically, they had not shown that they had special expertise on the matter of the structuring and pricing of transition bonds.

NJBUS was an active participant in the rate unbundling, stranded costs, and restructuring proceedings, presenting affidavits and testimony of numerous witnesses. As a representative of large business users of electricity, their expertise was useful in those proceedings. However, once the amount of stranded costs recoverable was determined, the matters to be resolved in the securitization proceedings ÄÄ how to structure, market, sell, and issue transition bonds ÄÄ required the type of technical financial expertise available from the BPU's financial adviser, Bear Sterns and Co. NJBUS does not offer any specific way it could have helped in these proceedings. Furthermore, the BPU had the input of the RA, which vigorously represents consumers of electricity in the State. The BPU did not abuse its discretion rejecting NJBUS's motion to intervene.


The administrative actions in this case were the culmination of an unusual hybrid of quasi-adjudicative and quasi-legislative proceedings. The short time period in which the Act mandated introduction of retail competition and rate reductions was in very substantial part responsible for any departure from the standard fare of hearings and rulemaking. However, we unhesitatingly conclude the essential requirements of due process were provided to the parties throughout the hearings, comment periods, and settlement negotiations. None of the procedural irregularities alleged by the parties rise to the level of a denial of constitutional due process, a violation of the APA, or of the Act. The proceedings were marked by full and vigorous participation, reflecting the full range of both public and special interests.



The RA and NJBUS challenge several aspects of the BPU's Final Decision as unsupported by the evidence and arbitrary. They allege that (1) the BPU's valuation of generation-related assets for the GENCO transfer failed to reflect full market value of the assets, (2) the shopping credits established by the BPU were not high enough to foster competition, (3) PSE&G's reliance on deferred accounting violated the Act, (4) PSE&G's use of excess depreciation reserve funds to achieve rate reductions is inconsistent with the Act, (5) the BPU allowed PSE&G to securitize more than the 75% of stranded costs allowed under the Act, and (6) PSE&G failed to pass through to customers all savings from securitization.

An appellate court will not reverse a decision of an administrative agency unless it is arbitrary, capricious, or unreasonable or it is not supported by substantial credible evidence in the record as a whole. Henry v. Rahway State Prison, 81 N.J. 571, 579-80 (1980). In determining whether an agency decision is based on sufficient credible evidence, this court gives "due regard" to the agency's expertise when this is a factor. In re Taylor, 158 N.J. 644, 656 (1999).


The RA and NJBUS contend that the BPU violated the Act by allowing PSE&G to transfer its generating assets to GENCO at an amount below full market value, which led to higher stranded costs eligible for recovery from customers. They claim that instead of relying on an administrative estimate based on predictions of future electric market prices, the BPU should have based its calculation on post-hearing out-of-state sales of comparable electric generation plants in the national market. They also contend that the BPU did not include a valuation for PSE&G's generation-related assets, such as fuel supplies and contracts. Finally, the RA faults the BPU for waiving the procedural requirement of petitioning for a transfer of assets and NJBUS faults the BPU for allowing the transfer of assets before promulgation of regulations on such transfers.

N.J.S.A. 48:3-55(d) permits the transfer of an electric utility's assets to an affiliate at "full value," which is to be determined by the BPU:

Pursuant to rules and regulations to be adopted by the board, the transfer of electric public utility assets from an electric public utility to a related competitive business segment of that electric public utility or of a public utility holding company, other than in the ordinary course of business, shall require board approval, and shall be recorded at full value as determined by the board.

The market value of generating assets that are transferred to an affiliate directly affects the quantification of stranded costs:

For the purposes of quantifying the magnitude of stranded costs eligible for recovery via the market transition charge, the board shall require the electric public utility to demonstrate the full market value of each eligible generating asset or power purchase commitment over its remaining useful life or term and, fixing the level of the market transition charge, the board shall reach a determination as to the market value of such eligible assets and commitments, or implement a mechanism for such value to be determined. [N.J.S.A. 48:3-61(e).]

The electric utility has a duty to mitigate stranded costs by, among other things, obtaining the highest market value of its generating assets:

For the purposes of quantifying the magnitude of stranded costs eligible for recovery via the market transition charge, the board shall require or impute all reasonably available measures for the electric public utility to mitigate the quantity of stranded costs, by: . . . (2) Maximizing the market value of the generating asset or purchase commitment. [N.J.S.A. 48:3-61(f)(2).]

The Act does not specify what methodology should be used in determining the value of assets to be transferred to an affiliate.

At the OAL proceedings, because PSE&G was not yet proposing immediate transfer of its generation assets to an affiliate, the value of those assets was litigated in the context of determining the amount of stranded costs PSE&G could recover for each of its generating plants. In his Initial Decision, the ALJ discussed the "administrative estimate" method of quantifying the market value of generation assets, which was relied on by PSE&G and most of the intervenors:

Absent divestiture, an administrative determination must be made to arrive at a quantification of stranded costs. The Company's methodology, which was broadly followed by all intervenors in their studies, was premised on the fact that market value can be estimated administratively by utilizing a market price forecast. The forecasted market energy price and capacity price, applied to the forecasted output of particular generating assets, is used to derive a projected market revenue of each facility on an annual basis. Forecasted annual cash expenditures including fuel, operation and maintenance (O & M) expenses, capital additions, taxes, administrative and general expenses and other ancillary costs are then subtracted from the projected annual market revenues. A comparable analysis is performed for each generating facility, as well as for each power purchase agreement with NUG contractors. The net results are discounted back to the present value using a discount rate of 8.42 percent, this value being based upon the Company's 1992 cost of capital, using the Company's capital structure provided in the last base rate case.

The ALJ then discussed the exceptions taken to this methodology by the RA, Enron, and the BPU's auditors, including those testified to by Michael Dirmeier on behalf of the RA, and PSE&G's responses to those exceptions. The ALJ agreed to some of the points made by the RA, Enron, and the BPU staff, and he recommended that certain adjustments be made to PSE&G's forecast assumptions.

In its Final Decision, in response to arguments of some of the parties, the BPU found that it was not necessary to reopen the proceedings and take additional evidence on recent sales of generating assets in other states, due to the extensive hearings already held on the valuation issue and the lack of direct relevance of those sales, somewhat "instructive" though they might be:

With respect to the valuation of the assets being transferred, there is a direct link between the value assigned these assets with respect to the transfer, and the magnitude of PSE&G's stranded costs: the higher the assigned value, the lower the remaining stranded costs. The issue of the value of PSE&G's generation assets was litigated at length in the stranded cost proceeding, as described in the Initial Decision and summarized hereinabove. Extensive testimony with respect to both the proper net book value of the assets to be utilized for purposes of stranded costs, as well as the net present value cash flows forecasted to be generated by the generation facilities over their remaining lives was presented in evidence at the Office of Administrative Law. The discounted net cash flow analysis approach, which was utilized by PSE&G in its stranded cost calculation and utilized as well by other parties' witnesses in the case (albeit with different assumptions) represents an analysis that would be undertaken by a potential bidder to determine its offering price in an asset auction process. The ALJ weighed the arguments and rendered findings with respect to the various inputs, variables and assumptions underlying a discounted cash flow analysis, including market energy and capacity price forecasts, forecasted capital additions and operation and maintenance costs, unit output and rates of return. We FIND that additional hearings are not required on this issue because there is sufficient basis in the record for a determination of the value of PSE&G's generation assets, and we FURTHER FIND that all parties have had ample opportunity during the proceedings to advance their arguments and introduce evidence with respect to the value of these assets.

As summarized above, in the comments on the proposed Stipulation, a number of parties urged the Board to consider the results of various recent fossil fuel generation divestitures through the country, arguing that recent data indicates that, when put up for sale and competitive bid, electric utility fossil fuel generation has fetched prices in excess of book value. While generation trends as to the results of industry-wide asset sales may be somewhat instructive and while, as discussed below, we have considered them and taken them into account in our decision, we concur with the comments received from PSE&G that it is impossible to reasonably attempt to extrapolate PSE&G's asset values from the results from sales of other utilities' generating assets. Any number of unique and individual factors associated with a particular utility's assets may exist which would justify divergent outcomes or plant values. These factors include plant vintage and conditions, heat rates, location, state and/or local environmental regulations or restrictions, environmental liabilities, fuel restrictions, fuel commodity and transportation costs, labor agreements, state and/or local tax liabilities and market price conditions. These factors, as they apply specifically to PSE&G's assets, were included in this proceeding as part of the stranded cost calculations, as the discounted net cash flow analyses prepared by PSE&G and several other parties considered all future costs and revenues associated specifically with each individual PSE&G generating facility. A proposed analysis to bring the purported comparable sales into comparability was not offered by the proponents of Stipulation II, nor is it likely that such an analysis could be readily performed. We FIND, for the foregoing reasons, that it would be unreasonable to rely upon these recent sales as the basis for a determination of the value of PSE&G's generating assets. We FURTHER FIND that there is ample support in the record for the Board to determine the market value of PSE&G's generating assets, and that the discounted net cash flow analyses presented in the stranded cost proceeding are the appropriate mechanism to be utilized to render such a determination.

However, the BPU did rely on recent industry divestiture information in deciding that the market value of PSE&G's generating assets was $135 million more than the company proposed in Stipulation I:

[W]e HEREBY FIND the level of net-of-tax owned generation stranded cost for PSE&G to be $2.94 billion. This amount, when compared to the level of net-of-tax stranded costs which PSE&G would be afforded the opportunity to recover via the proposed Stipulation ($3.075 billion), results in a reduction to net-of-tax stranded cost recovery of $135 million. This decrease of $135 million in net-of-tax stranded cost vis-a-vis the level proposed in the Stipulation represents a finding by the Board that the market value of PSE&G's owned generation assets is $135 million more than that assumed in the Stipulation. The comments received in response to the Stipulation, regarding recent industry divestiture information, would suggest that this increased value, vis-a-vis the Stipulation, should be assigned to the Company's fossil fuel generating units, since these types of units, as opposed to nuclear generating facilities, have obtained sales premiums. We therefore FIND, consistent with the general industry trends which have been noted in a number of the comments received, that the transfer value of the Company's fossil generating assets should be increased by $135 million. Accordingly, we FIND that the generating assets shall be transferred to Genco at the following market valuations: $0.046 billion for nuclear; and $1.857 billion for fossil. Thus, the full value of the generating asset transfer is $1.903 billion, in satisfaction of the requirements of subsection 7(d) of the Act, N.J.S.A. 48:3-55(d), which we FIND to be the full market value of the generating assets over their remaining useful life in accordance with the provision of subsection 13(e) of the Act, N.J.S.A. 48:3-61(e).

In addition to the $1.903 billion valuation of the generating assets that PSE&G will transfer to GENCO, the BPU allowed PSE&G to recover up to $540 million more in stranded costs (reduced from the $600 million proposed in Stipulation I) through an MTC, which the BPU referred to as a "transfer premium." The BPU calculated this as the difference between the $2.94 billion in total net-of-tax stranded costs and the $2.4 billion that it would permit PSE&G to securitize.

However, as NJBUS points out, $540 million is also the difference between the $1.903 billion asset valuation and the $2.443 billion referred to later in the Final Decision as the "final and fixed transfer value . . . which is the fair market value of the assets transferred considering all revenues derived from the BGS contract [between PSE&G and GENCO]." The BPU asserts that this reference to $2.443 billion was "merely intended to adjust the number contained in Attachment 4 [to Stipulation I] downward to reflect the fact that the BPU had reduced the 'transfer premium' included in Attachment 4 from $600 million to $540 million." Attachment 4, titled "Generation Fixed Transfer Value," consists of the following computation:

$5.058 billion Net After Tax Book Value

(3.300) Stranded Cost

$1.768* Transfer Value

$600 MTC

$2.368 Amount Paid by Genco to PSE&G

*Plus Generation-Related Assets, including Nuclear Fuel and Materials & Supplies at Book Value.

Thus, $1.903 billion in transfer value of assets plus $540 million in MTC equals $2.443 billion, the amount paid by GENCO to PSE&G. However, we do not think that this calculation has any effect on the parties' challenge to the transfer premium.

Essentially, the RA and NJBUS argue that there is no justification for a transfer premium. The BPU justifies the $540 million transfer premium by saying that it benefits PSE&G's customers by allowing the utility to recover its stranded costs but transferring the risk of non-recovery of stranded costs to GENCO:

These funds shall be used by PSE&G, much like the proceeds from the transition bonds, to refinance and/or retire its debt and/or equity. This will benefit the utility and, ultimately, the customers of PSE&G by further reducing PSE&G's cost of capital. PSE&G will have the opportunity to recover up to $540 million, net-of-tax, through any retained retail adder associated with non-switching or returning customers, the MTC (exclusive of the NTC and the MTC-Tax) and the amount funded by the excess distribution reserve amortization; which funds will be, in turn, transferred to Genco as received pursuant to the terms of the BGS contract (as modified and approved herein). At the end of the Transition Period, the recovery of the $540 million will be reconciled with actual collections as set forth herein, with PSE&G being at risk for any shortfall and customers receiving the benefit of any overrecovery via a credit of such excess amount to the SBC. We FIND this mechanism to be consistent with the provisions of section 13 of the Act, N.J.S.A. 48:3-61, which require that we afford the utility the opportunity, but not a guarantee, for recovery of generation-related stranded costs, and that . . . we reconcile stranded cost recoveries to ensure that the utility will not collect in excess of its stranded costs. The above-described mechanism has the added benefit of transferring the risk of non-recovery of stranded costs to Genco, the unregulated affiliate, and not the utility, since PSE&G will receive the $540 million from Genco up-front in the form of a transfer premium.

The BPU's decision to make its fact findings as to asset valuation based on the "administrative estimate" method used by the parties during OAL proceedings and approved of by the ALJ was reasonable. The BPU explained its reasons for adopting the methodology and there is absolutely no doubt there was substantial evidence in the record to support its findings on valuation based on that method. In re PSE&G Co., 304 N.J. Super. at 273-74. Whether to reopen the proceedings in order to consider new evidence of speculative relevance regarding the sale of generating assets in other states was within the BPU's sound discretion. N.J.A.C. 14:1-8.4(b). *fn2 Considering the time-consumption and difficulty of extrapolating useful comparable information from out-of-state transactions, the rather insubstantial offer of proof (see R. 1:7-3), and the compressed time frame within which the BPU had to proceed to implement the Act, we conclude that the BPU did not abuse its discretion in refusing to reopen the proceedings on asset valuation.

NJBUS cites In re MCI Telecom. Corp., 263 N.J. Super. 313, 318 (App. Div. 1993), in support of its position that the BPU may not ignore significant new developments in reaching its decision. That case involved the rejection of a petition which re-examined the subject of local competition for the first time in six years, at a time when the telecommunications industry had changed drastically, and when the original decision had been based on little hard evidence. Here, there was ample evidence on which to forecast the value of assets using an approved methodology. The out-of-state market-price evidence in fact was considered by the BPU and resulted in a $135 million increase in the transfer value of some of PSE&G's assets.

The BPU's decision to allow recovery of the $540 million in stranded costs through an MTC must be treated with deference because, as the administrative agency charged with enforcing the Act, its interpretation of the Act and its policy decision should be given great weight. Nelson v. Board of Educ. of Tp. of Old Bridge, 148 N.J. 358, 364 (1997); see Chevron U.S.A. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 844, 104 S. Ct. 694, 81 L. Ed.2d 694, 703 (1984) ("[C]onsiderable weight should be accorded to an executive department's construction of a statutory scheme it is entrusted to administer, and the principle of deference to administrative interpretations"). The Act allows for, but does not mandate, a utility's full recovery of its stranded costs. The MTC is one mechanism for recovering stranded costs. The Final Decision allows for a true-up at the end of the transition period so that PSE&G will not be able to recover more than its stranded costs in violation of the Act. We see no basis for overturning this aspect of the decision.

The RA also asserts, based on the calculations in Attachment 4 to Stipulation I, that the BPU's asset valuation is mathematically inconsistent and arbitrary. As the RA says, the BPU did not make an independent determination of the net-after-tax book value of its generating assets and did not modify the $5.068 billion figure asserted by PSE&G. The RA goes through a series of calculations, but the crux of its argument is that the market value of $1.903 billion, plus stranded costs of $2.94 billion, should add up to the net book value of $5.068 billion; but they add up to only $4.843 billion, $225 million less than $5.068 billion. In Attachment 4, the transfer value proposed by PSE&G ($1.768 billion) and the stranded cost figure it proposed ($3.300 billion) did indeed add up to $5.068 billion. The BPU does not address this discrepancy in its brief but PSE&G explains it by pointing out that in Stipulation I PSE&G agreed to a total reduction of $225 million in unsecuritized generation-related stranded costs. The RA did not respond to this explanation in its reply brief, presumably conceding the validity of the explanation.

Both the RA and NJBUS fault the BPU for ordering the transfer of generation-related assets such as contracts, materials, and fuel at book value rather than fair market value and without any listing of these assets or litigation on them. Stipulation I proposed the transfer of generation-related assets such as "materials, supplies, and fuel" at book value and the BPU adopted the proposal in its Final Decision:

PSE&G will transfer at book value at the time of transfer other generation-related assets including materials, supplies, and fuel, which book value we find to be the full value for such generation-related assets in accordance with subsection of the Act, N.J.S.A. 48:3-55(d). Such transfer prices ensure that PSE&G receives full value for the Generation Facilities and related assets and that PSE&G will not retain any liabilities associated with the transferred Generation Facilities or other generation-related assets and shall assure that customers' responsibility for stranded costs is established at the lowest reasonable level. [(emphasis added).]

N.J.S.A. 48:3-55(d) gives the BPU the discretion to determine the full value of assets, and the BPU determined that the book value of these types of assets was their full value. The RA had an adequate opportunity to comment on this aspect of the transfer at book value.

However, the BPU adopted another aspect of Stipulation I, that regarding the transfer of generation-related contracts to GENCO, without comment as to any inherent value of the contracts:

In order to ensure that PSE&G does not retain any risk or liabilities associated with the electric generating business after the Generating Facilities have been transferred, the Board hereby orders that all contracts (except for the NUG contracts) associated with the electric generating business, including, but not limited to, wholesale electric purchase and sales agreements, fuel contracts, real and personal property interests, and other contractual rights and liabilities, be transferred from PSE&G to Genco simultaneous with the transfer of all generating assets, and to substitute the Genco for PSE&G as the party(s) to any such contracts.

PSE&G does not explain why the contracts should be transferred without a valuation. The BPU states that it is "reasonable to assume that contracts and rights related to generating assets would be made available to potential purchasers of those assets at book value" despite the fact that the Final Decision does not state that the contracts will be transferred at book value. No one seemed to propose that any of the contracts were intrinsically valuable. We are not convinced by anything in this record that any generation related contracts had any measurable intrinsic net value. Indeed, some could become a decided liability, depending on market fluctuations.

We now turn to the purely procedural aspects of appellants' arguments. The RA contends that the BPU violated N.J.A.C. 14:1-5.6 when it waived this regulation's requirement that PSE&G petition it for approval to sell its generating property to GENCO. The only reference to this regulation in the Final Decision was as follows:

The advertising requirements under N.J.A.C. 14:1-5.6 are waived because of the extensive nature of the record regarding valuation of the assets being transferred and no further authorizations by the Board are required to effectuate this transfer provided that all other regulatory approvals are obtained on a basis consistent with this Order.

The advertising requirements referred to above are in N.J.A.C. 14:1-5.6(b): property worth over $500,000 must be advertised for sale at least twice in the county in which it is located. Those requirements may be waived, under N.J.A.C. 14:1-5.6(i). In addition, under N.J.A.C. 14:1-1.2(a), procedural regulations may be relaxed for good cause and the rules are to be liberally construed so as "to permit the Board to effectively carry out its statutory functions and to secure just and expeditious determinations of issues properly presented to the Board." Here, when the BPU said that it was waiving the advertising requirements of N.J.A.C. 14:1-5.6, "due to the extensive nature of the record regarding valuation of the assets being transferred," it was obviously explaining why none of the petition requirements of that regulation were required, rather than just the advertising requirement of section (b). Stipulation I was, in effect, a proxy petition for the BPU's approval of the transfer of assets. The BPU did not abuse its discretion in waiving the petition requirement.

In its reply brief, NJBUS raises for the first time the contention that N.J.S.A. 48:3-55(d) requires the BPU to promulgate regulations regarding valuation of asset transfers to an affiliate before it approves any such transfers. N.J.S.A. 48:3-55(d) provides that "pursuant to rules and regulations to be adopted by the board," the transfer of a utility's assets to an affiliate "shall require board approval."

The purpose of rulemaking is to give the public notice of anticipated agency action and an opportunity to participate and comment on the action before it becomes final, as well as to give the agency the benefit of the information that the public has to offer. Metromedia, Inc. v. Division of Taxation, 97 N.J. 313, 331 (1984). Here, over thirty intensely interested intervenors of all stripes had an opportunity to participate in the OAL proceedings, at which PSE&G's generating assets were valued for stranded cost purposes, and then by commenting on Stipulation I, which proposed the immediate transfer of generating assets. NJBUS has shown no harm by the BPU's approval of the transfer without first adopting regulations. Yahnel v. Board of Adjustment of Jamesburg, 76 N.J. Super. 546, 550 (Law Div. 1962), aff'd, 79 N.J. Super. 509 (App. Div.), certif. denied, 41 N.J. 116 (1963) (holding that Board's granting of variance without first adopting statutorily required rules did not invalidate Board's action when plaintiffs failed to show how they were harmed by the failure to adopt rules and they had a full opportunity to present their case to the Board). NJBUS also had the full opportunity to present its case.


"Shopping credits" are the amount deducted from customers' electric bills when they switch to a nonutility supplier for their basic generation service. N.J.S.A. 48:3-51. NJBUS contends that the level of shopping credits approved by the BPU is too low to encourage competition, their purpose under the Act. It faults the BPU for setting the credits at the same level as established by the Philadelphia Electric Company (PECO), citing a witness who testified that the market forces which made PECO shopping credits acceptable in 1998 had changed by 1999. Therefore, NJBUS asserts BPU's decision, which relied on out-of-date market data from a contiguous state, was arbitrary, capricious, and unreasonable, and a remand is required in order to develop a record which will result in more reliable forecasts of energy prices.

Under N.J.S.A. 48:3-52(b), electric utilities that provide basic generation service must also provide

shopping credits applicable to the bills of their retail customers who choose to purchase electric generation service from a duly licensed electric power supplier. The board shall determine the appropriate level of shopping credits for each electric public utility in a manner consistent with the findings and declarations of the Legislature . . . . The reduction in electric public utility rates . . . shall be consistent with the goals of the act, including the creation of shopping credits . . . .

Among the policies advanced in the legislative findings and declarations section of the Act are lowering the cost of energy and fostering diversity in the supply of electric power by opening New Jersey to competitive markets. N.J.S.A. 48:3-50(a)(1), (2), and (7). N.J.S.A. 48:3-52(b) gives the BPU the discretion to determine the level of shopping credits which will encourage competition and will relate appropriately to the level of rate reductions.

In Stipulation I, PSE&G proposed shopping credits averaging 5.03 cents per kWh in 2000, rising to 5.10 cents per kWh in 2003. In Stipulation II, NJBUS and the other signatories proposed shopping credits averaging 5.40 cents per kWh in 2000, based on the alleged PECO level of shopping credits, with adjustments for New Jersey costs and cost increases in the wholesale market. In an affidavit attached to Stipulation II on behalf of MAPSA, John Rohrbach, who was involved in the PECO rate-setting negotiations, said that "the underlying market forces that made PECO Shopping Credits acceptable have changed considerably since April 1998," when the PECO settlement was signed. He pointed specifically to higher energy prices. He also mentioned higher taxes in New Jersey. Rohrbach acknowledged that PSE&G's proposed shopping credit level was higher than PECO's, but said that on "a real basis" they were lower and insufficient to support a truly competitive retail market.

The BPU adopted the shopping credit proposal in Stipulation I. In its Final Decision the BPU first emphasized the interrelated character of the level of rate reductions and shopping credits:

[U]nder a price cap as mandated by the Act, once the other unbundled rate components, including provisions for stranded cost recovery, are established, higher shopping credits would result in lesser rate reductions, and vice versa, absent the deferral of the recovery of costs into some future period. In a very real sense then, the Board is required by the Act to balance the achievement of two crucial, yet potentially conflicting factors. All other things being equal, a movement too far in one direction, in favor of larger shopping credits at the expense of lesser rate reductions, would benefit electric power suppliers and/or shopping customers, at the expense of customers who do not switch suppliers. Conversely, a move too far in the other direction in favor of lower shopping credits to achieve higher rate reductions would benefit non-shopping customers, while potentially inhibiting the development of a competitive market by making it less attractive for third party suppliers to enter the marketplace, thus resulting in diminished opportunities for customers to switch suppliers.

After establishing the level of rate reductions during the four-year transition period, the BPU turned to the level of shopping credits:

[I]t is plainly evident that the shopping credits embodied in the Stipulation are significantly higher than those proposed by the Company in its filing, and reflect consideration of the criticism leveled at that proposal by the parties to this proceeding, . . . some of which were found to have merit by the ALJ. The proposed shopping credits in the Stipulation reflect market capacity costs, in addition to market energy costs, and also include a retail adder as recommended by the ALJ. The market energy and capacity costs reflected in the shopping credits contained in the Stipulation are consistent with the market price projections presented in the testimony of Company witness Loxley. The shopping credits in the Stipulation also make provision for transmission costs, and the losses and sales tax which will be incurred by third party suppliers. We note that the shopping credits are on par with, and indeed on average slightly higher than those in the PECO service territory in Pennsylvania. These higher shopping credits are noteworthy because, both during the evidentiary proceeding and in comments on the Stipulation, various marketers have pointed to the PECO service territory as having the most robust and active retail electricity marketplace in the nation, and the PECO service territory lies in the same regional electricity marketplace as PSE&G.

The BPU faulted the Stipulation II proposal on shopping credit levels:

[W]e find that the shopping credits proposed in Stipulation II are excessive, unsupported by the record, and based upon flawed reasoning. First, because of the inter-relatedness between shopping credits and the rate reductions, as addressed above, and having established herein the appropriate levels for the other unbundled rate components . . . and having found that Stipulation II's underlying financial analysis is flawed, the level of shopping credits proposed in Stipulation II would lead to either lower rate reductions or a significant deferral of cost recovery, which would lead to higher rates in the future.

The BPU went on to discuss the allegations in Rohrbach's affidavit regarding the comparison to PECO shopping credit levels:

[W]hile acknowledging that the shopping credits in the Stipulation are higher than those in PECO's territory, the proponents of Stipulation II assert that, on a "real" basis, the credits in the Stipulation are lower, citing asserted changes in the PJM electricity market and differences in costs between New Jersey and Pennsylvania. It is asserted in supporting affidavits that the credits in the Stipulation would have to be raised by about 0.6 cents in order to provide a comparable level of competition to that enjoyed by PECO customers. Based on our review of the submissions, the Board concludes that almost all of the claimed differences (approximately 5 of the claimed 6 mill average difference) relate to asserted increases in market prices since the PECO shopping credits were established. We FIND the claim that an increase in the shopping credits to reflect alleged market price increases is necessary in order to provide savings similar to those afforded in the PECO territory to be simply untrue; no provision was made in the PECO decision by the Pennsylvania Public Utility Commission ("PaPUC") to update the shopping credits to reflect changed market conditions, as is suggested be done here. To the extent that retail competition is flourishing in PECO's service territory, it is occurring at the fixed levels of shopping credits established by PaPUC in April 1998, despite alleged increases in market price conditions. Moreover, even assuming arguendo, that the cited market prices presented via a post-hearing affidavit are accurate, it is important to note that while the Stipulation's shopping credits are premised on long-term pricing forecasts which have been the subject of substantial review in the proceeding, the proponents of Stipulation II would have the Board premise a decision to set shopping credits for four years based upon a current price condition; however, such price conditions may change daily, if not more often. Accordingly, the Board is not persuaded that it reasonably could or should base its decision on this "snapshot" market information. Rather, we FIND that it is more appropriate to establish the shopping credit levels based upon the market price forecasts over the four year Transition Period which have been presented in this proceeding and which have been the subject of extensive review in the record.

The BPU's acceptance of the proposal in Stipulation I was based on a careful review of the record, including the Rohrbach affidavit. It recognized several important facts: PSE&G had agreed to a higher level of shopping credits than it originally proposed, Stipulation I took into account the ALJ's recommendation that there be a retail "adder" (which represents ancillary costs such as administration and marketing), and the level of shopping credits proposed in Stipulation I was consistent with the PECO level of shopping credits, which successfully had encouraged competition in a nearby geographic area. The BPU observed that PECO succeeded based on forecasts of energy costs rather than on periodic updates based on actual costs and saw no reason to change that successful formula. There was ample evidence in the record on forecasts during the transition period. Thus, there is nothing arbitrary about the BPU's decision.


The RA contends that the BPU violated the Act when it allowed PSE&G to amortize $568.7 million in excess money it had already collected from its customers to partially fund its statutory rate reduction. The RU says that this contradicts another aspect of the BPU's decision, where it rejected PSE&G's proposal to use $60 million in anticipated overrecovery balance in its levelized energy adjustment clause (LEAC) as of July 31, 1999 to fund part of its rate reduction.

The Act does not specify how the rate reductions are to be achieved or the source of funding for them. N.J.S.A. 48:3-52(d) -(j). It does, however, state that the reductions should be "sustainable," N.J.S.A. 48:3-52(f), and that the maximum level of rate reduction "shall be sustained at least until the end of the 48th month following [August 1, 1999]." N.J.S.A. 48:3-52(j). The only caveat, but a very substantial one, regarding rate reductions is they should not "impair the electric public utility's financial integrity." N.J.S.A. 48:3-61(h).

Paragraph 4 of Stipulation I proposed:

The parties agree that an excess electric distribution reserve in the amount of $568.7 million is to be amortized over three years and seven months beginning on January 1, 2000 and ending July 31, 2003. Amortization amounts will be $125 million in the year 2000, $125 million in the year 2001, $135 million in the year 2002, and $183.7 million in the year 2003.

In its Final Decision the BPU adopted this proposal verbatim. Stipulation II, to which the RA was a signatory, proposed that 60% of the $569 million excess depreciation reserve be applied to offset the rate increases it believed would occur in years five and six (2004 and 2005), after the transition period's mandatory rate reductions terminated; only the remaining 40% would be used to fund rate reductions during the four-year transition period. In its comments on Stipulation I, the RA objected to the amortization of electric depreciation reserve funds to fund rate reductions "because it represents excess money that has been collected from ratepayers, which would normally be returned via a reduction in depreciation rates." Yet, at the same time, the RA accepted the use of this money to fund mandatory rate reductions between 1999 and 2003, seemingly contradicting its own position.

In its Final Decision, the BPU said that the use of 60% of the depreciation reserve funds in the fifth and sixth years was "inappropriate, since the $569 million is already embedded in the Company's petition, and fully utilized and relied upon in the ALJ's recommended range of rate reductions, as well as to partially fund the rate reductions." Use of this amortization to fund additional rate reductions would "double-count" the source of funds.

The BPU did agree with the RA's comments regarding the LEAC over-recovery balance as of August 1, 1999 which "consists of funds over-collected from and appropriately returned to the ratepayers of PSE&G, with interest, and thus should be utilized for the benefits of customers, not the Company." The BPU found that the over-recovered amount should offset the NTC deferred balance rather than fund additional rate reductions in years five and beyond, as proposed by the RA. In this way the LEAC monies will be "available to mitigate the impact of recovery of any other deferred costs in year five and beyond."

Thus, the RA explicitly accepted the propriety of the use of depreciation reserve monies to fund rate reductions during the four-year transition period. Furthermore, the BPU considered the RA's alternate proposal and rejected it based on its finding that it double-counted the depreciation reserve monies. It did not allow the use of LEAC monies to fund rate reductions but there is a difference between LEAC monies, which are normally returned directly to consumers with interest, and excess depreciation funds, which are returned indirectly via a reduction in depreciation rates. The BPU's decision in this regard was within its discretion and did not violate the Act.


As discussed above, in IV B 3, the BPU accepted the Stipulation I proposal that PSE&G be permitted to defer the actual costs related to the SBC and NTC charges. The RA contends that allowing PSE&G to defer these costs to a future time in effect makes any present rate reductions illusory by preordaining that there will be a rate increase after the four-year transition period. Such a rate increase, the RA says, violates that Act's mandate, under N.J.S.A. 48:3-52(f), that the utilities implement a "sustainable aggregate rate reduction." Also, the Final Report specified that utilities could not be guaranteed 100% recovery of stranded costs because the mandatory rate reductions might make that impossible.

As pointed out in V(C) above, there is nothing in the Act which specifies the way in which the rate reductions are to be funded. N.J.S.A. 48:3-52(d). Nor is there anything in the Act that prohibits the use of deferred accounting. In fact, the Act gives the BPU the discretion to permit an "alternative accounting process" which allows a utility to provide basic generating service while effecting rate reductions if the BPU determines that such a process is "necessary to mitigate the impact of market price fluctuations and to sustain such rate reductions." N.J.S.A. 48:3-57(b)(3).

Indeed, deferred accounting is an accepted method where there are fluctuations in costs which must be periodically adjusted, such as utilities' fuel adjustment clauses. N.J.A.C. 14:12-4.1(b). For example, the LEAC permits utilities to charge customers based on estimates as to future fuel costs and then to make later periodic adjustments to reflect actual costs. In re Atlantic City Elec. Co., 310 N.J. Super. 357, 362 (App. Div. 1998).

Here, in its Final Decision, the BPU considered it appropriate and "consistent with the intent of the Act" to allow PSE&G "to fully recover reasonable and prudent expenditures for the types of programs reflected in the SBC" ÄÄ the kinds of programs that benefit society, such as environmental, consumer education, and nuclear plant decommissioning. The BPU found that "deferred accounting treatment of under and over-recoveries . . . is necessary and appropriate in order to provide for full recovery [for social programs] under the legislatively required price cap mechanism."

Stipulation I provided for recovery of above-market nonutility generator (NUG) contract costs through an NTC set at an initial level of $183 million annually during the four-year transition period, with the difference between NTC recoveries and the actual above-market NUG contract costs subject to deferred accounting and interest accrual on under or over-recoveries. The BPU found that this mechanism would ensure "timely pass-through" to customers of the benefits of any NUG contract renegotiations, as required under N.J.S.A. 48:3-61; and the "periodic review and adjustment of the charge [would] ensure that the utility will not collect charges that exceed actual stranded costs."

The deferred accounting method for SBC and NTC charges allows for a reconciliation of the estimated and actual costs of these programs, and will benefit customers if there is an over-recovery. The deferral of the actual costs may not necessarily lead to rate increases after 2003, but even if they do, there is nothing in the Act that prohibits such increases. The language in N.J.S.A. 48:3-52(f) regarding a "sustainable aggregate rate reduction" must be read in conjunction with N.J.S.A. 48:3-52(j), which leads to the conclusion that the rate reductions are only mandated through July 31, 2003. However, the legislative findings make it clear that the Legislature believed that retail competition would lead to competitive rates. N.J.S.A. 48:3-50(b)(5) and (6). We must recall, under N.J.S.A. 48:2-21(d), utilities must file a petition for a rate increase and the BPU may order a hearing before it determines whether to approve any rate increase, an additional safeguard for consumers.


N.J.S.A. 48:3-62(c)(1) allows the BPU to authorize securitization "in a principal amount of up to 75 percent of the total amount of the electric public utility's recovery-eligible utility generation plant stranded costs." The BPU authorized PSE&G to issue up to $2.525 billion of fifteen-year transition bonds, which represented $2.4 billion of the $2.94 billion net-of-tax stranded costs ("grossed up" to $4.97 billion to account for federal and state taxes) plus $125 million of transaction costs, which include the fees and expenses of issuing, selling, and refinancing or refunding its debt. According to the BPU, this represented securitization of 48% of PSE&G's total eligible stranded costs. The BPU also allowed the anticipated taxes (about 40% and up) related to securitization ÄÄ the amount responsible for grossing up the $2.94 billion figure to $4.97 billion ÄÄ to be collected through a separate MTC tax over the course of fifteen years.

The RA contends that the BPU's decision allows PSE&G to securitize 82% of its stranded costs, if the net-of-tax $2.4 billion figure is calculated as a percentage of the net-of-tax $2.94 billion figure. The RA says this violates the purpose of N.J.S.A. 48:3-62(c)(1), which allows for securitization of over 75% of stranded costs only if a utility divests itself voluntarily of its generating plant, thus encouraging divestiture, because PSE&G has not divested but only transferred its generating facilities to an affiliate. Furthermore, the RA says that the MTC tax is simply a gimmick to circumvent the 75% limit on securitization.

The Act defines "bondable stranded costs" as including the cost of retiring existing debt; federal, state, and local tax liabilities associated with stranded costs; and the costs incurred to issue, service, or refinance transition bonds. N.J.S.A. 48:3-51. Thus, the BPU did not violate the Act by allowing the transaction costs of $125 million to be securitized. Nor did it violate the Act when it "grossed up" the $2.94 billion net-of-tax figure for total eligible stranded costs and arrived at $4.97 billion as the total that was "bondable." The only perhaps debatable question is whether the $2.4 billion figure is a net-of-tax figure, as the RA claims, and thus should not have been compared to the "grossed up" figure of $4.97 billion to arrive at a percentage of eligibility for securitization purposes.

In its Final Decision, after determining that the $2.94 billion net-of-tax stranded costs should be grossed up so that PSE&G could recover the state and federal income and like tax liability it would incur, the BPU said:

[W]e concur with the concerns raised by Staff during the litigation of these proceedings, as well as the RPA and others during the comment period, and HEREBY REJECT as inappropriate and, in our view, inconsistent with the intent of the Act, the proposal within the Stipulation, supported by all signatories thereto except NJCU, that all taxes related to securitization be recovered through the transition bond charges. We conclude that the transition bond charge is appropriately utilized to provide and ensure collection of the principal and interest payments on the transition bonds. The assured collection of the bond principal and interest provided via the irrevocable transition bond charge is necessary in order to obtain the highest possible rating on the bonds, which, in turn, will result in the lowest possible interest rate on the bonds and resultant maximized ratepayer savings. We do not believe it appropriate, nor consistent with the intent of the Act, that the utilities' tax obligations be collected via the irrevocable transition bond charge. As indicated previously, however, it is entirely appropriate and necessary that the net-of-tax stranded cost number be grossed-up for ratemaking purposes, and that PSE&G be afforded the opportunity to fully recover these taxes.

Accordingly, the Board HEREBY DIRECTS that a Market Transition Charge be established, coincident with the establishment of the transition bond charge, . . . specifically for the collection of securitization-related Federal Income and State Corporate Business Taxes ("MTC-Tax"). The taxes to be collected through the MTC-Tax shall reflect the grossed-up revenue requirements associated with the net-of-tax amount of stranded costs, together with the estimated level of transaction costs, authorized herein for recovery through securitization.

Since the securitization-related taxes (responsible for the $2.94 billion figure being grossed up to $4.97 billion) are to be collected through a separate MTC tax, the $2.525 billion that the BPU authorized PSE&G to securitize with transition bonds was a net-of-tax figure. This conclusion is supported by a statement made by the BPU auditors: "If the $2.5 billion securitization is 'grossed up' to include taxes, it becomes a $3.5 billion securitization issue. PSE&G calculated their stranded cost and their securitization to be net of or without income taxes."

The respondents do not specifically discount that argument, but rather distinguish the funds recovered through securitization from the money recovered through the MTC tax. For example, PSE&G points out that securitization allows it to get the funds immediately and use them to retire debt and equity capital immediately, whereas the MTC tax gives it access to funds over the fifteen-year life of the transition bonds and the ability use those funds to pay federal and state income taxes as incurred. The unalterable fact remains that PSE&G in reality will securitize only $2.525 billion of its total eligible gross stranded costs (inclusive of local, state and federal taxes) of $4.95 billion or about 51%. This is well below the allowable 75% total.

The BPU apparently and understandably believes it will be better for consumers to allow the federal and state tax liability to be recovered through the MTC tax rather than through securitization. By creating the MTC tax, though not explicitly provided for by the Act but suggested by the RA, the BPU allows PSE&G to recover the tax liability that grossed up the $2.94 billion stranded cost figure to $4.97 billion. We reject the RA's argument that the $2.4 billion actually securitized should be calculated as a percentage of the stranded costs that are not being recovered in some other way, or the net-of-tax figure of $2.94 billion. Doing so leads the RA to the conclusion that the BPU allowed PSE&G to securitize almost 82% of its stranded costs, 7% more than allowed under N.J.S.A. 48:3-62(c).

On this point, we simply disagree with the RA. In this situation the Act permits the BPU to authorize the issuance of transition bonds "up to 75% of the total amount of the electric public utilities recovery-eligible utility generation plant stranded costs," N.J.S.A. 48:3-62(c)(1), as determined by the BPU in accordance with N.J.S.A. 48:3-61. As noted, "bondable stranded costs" includes "federal, state and local tax liabilities associated with stranded costs recovery." N.J.S.A. 48:3-51. We see no violation of the text, purpose or intent of the Act; the total actual securitization is well below the permitted 75% level.


The RA contends that the BPU has ordered PSE&G to pass along to its customers only those savings associated with the first four years of securitization rather than all savings during the fifteen-year period during which TBC charges will be collected, which violates the Act. As discussed in IV D, above, the RA also faults the BPU for relying on PSE&G's September 2 and 10, 1999 attachments to its financing petition, which it says offered confusing new projections of savings from securitization over the full fifteen-year period. NJBUS adds that even the BPU's assurance it will review the "distribution rate design" before the end of the transition period to see whether any additional future savings should be passed along to ratepayers violates the Act, because the Act requires the immediate pass-through to customers of all securitization savings over the term of the bonds.

In a related argument, NJBUS contends that the Final Decision violated the Act when it incorporated a 1% prepayment of anticipated securitization savings into the 5% August 1, 1999 rate decrease; specifically, it points to the provision that requires all securitization savings be passed along to customers as soon as the bonds are issued.

N.J.S.A. 48:3-62(a) allows the recovery of stranded costs through the issuance of transition bonds and the imposition of TBC charges on customers. It also provides:

The entire amount of cost savings achieved as a result of the issuance of such transition bonds, whether as a result of a reduction in capital costs or a lengthened recovery period associated with otherwise recovery-eligible stranded costs or as a source of cash for the buyout, buydown or other restructuring of a power purchase agreement, shall be passed on to the customers of the electric public utility in the form of reduced rates for electricity. [N.J.S.A. 48:3-62(a) (emphasis added)].

The statute also provides that the issuance of transition bonds "will provide tangible and quantifiable benefits to ratepayers, including greater rate reductions than would have been achieved absent the issuance of such bonds and net present value savings over the term of the bonds." N.J.S.A. 48:3-62(b)(3). Furthermore, the rate reductions which result from the issuance of transition bonds "shall be made no later than the date on which the transition bond charge . . . becomes effective." N.J.S.A. 48:3-52(i).

Although securitization will not occur until this appeal is resolved, some of the savings anticipated from securitization are being passed along to customers even before the bonds are issued because the initial 5% rate reduction went into effect on August 1, 1999. Securitization will result in greater rate reductions during the four-year transition period than those required under the Act (13.9% rather than 10%). As the BPU said in the Final Decision, "if securitization is implemented" the proposed rate decreases will be increased to reflect any additional savings.

However, as the RA asserts, the transition bonds and TBC charges endure for fifteen years, and Attachment 2 to the BSCRO computes estimated savings to ratepayers from the transition bonds during the fifteen-year life of the bonds. But there are no mandatory rate reductions under the Act after the four-year transition period.

According to PSE&G, after the transition period ends, customers still will pay the company for distribution, transmission, and SBC and NTC charges, but they will be paying their power supplier for generation services. The only generation-related charge that customers will pay PSE&G is the TBC, and the savings from lower interest rates due to securitization will be passed along to customers through a TBC that will be lower than the MTC would have been absent securitization.

This explanation for the way securitization savings will be passed through to customers after the transition period comports with the BSCRO, which calls for periodic adjustments to the TBC so that it reflects the lowest possible interest rates over the life of the bonds. Although the Act mandates that transition bonds savings be reflected in rate reductions, it does not mandate any such reductions after 2003. These two aspects of the Act must be read in conjunction. The BPU resolved the tension or apparent contradiction in the Act by ordering a reasonable alternative way to pass through the savings to customers.

The only troubling aspect of the respondents' position on this issue is a disagreement between PSE&G and the BPU on the meaning of certain language in the Final Decision. The BPU points out that it said it would review the overall level of savings and the level of distribution rate design before the end of the transition period to determine "whether any additional future securitization savings should be passed along to ratepayers in year five and beyond." The BPU cites to the following passage of the Final Decision:

[W]e are concerned that, subsequent to the Transition Period, such rate design could have unintended and unnecessary impacts on PSE&G's customers, since the termination of rate reduction credit at the end of year four would, absent any other adjustment, result in an increase in rates in year five which would equal the amount of the credit in effect in year four. Moreover, the elimination of the credit in year five could result in an unpermitted shift in cost responsibility. Although it is not known at this time what the BGS [basic generation service] rate will be in year five or what the level of deferred balances for the SBC and NTC will be at that time, the Board is concerned that a simple removal of the rate reduction credit in year five without a reassessment of the other unbundled rate element, could result in total charges which exceed the total of the otherwise-appropriate unbundled rate elements. We also FIND it necessary and appropriate for the Board to review the overall level of rate savings as well as the level of the distribution rate design and the other unbundled rate components, including the SBC and the NTC, prior to the conclusion of the Transition Period to determine, among other things, whether any additional future savings should be passed along to ratepayers prospectively. [(emphasis added).]

In response to a reference by NJBUS to this portion of the Final Decision, PSE&G says that the BPU was referring to "potential savings from the SBC and NTC . . . not securitization savings." Indeed, the BPU Final Decision does not specifically refer to securitization savings, although the TBC is an unbundled rate component, just as the SBC and NTC.

We conclude the BPU's position that it will review rates to see if there should be post-transition period rate reductions does not violate the Act. If the BPU believes that the best use of securitization savings during the future period when rate reductions are not mandated is further rate reduction, then it can, in its discretion, so order. However, even if it does not do so, the securitization savings are being passed through to customers through the lowest possible TBC charges and lower MTC charges.

As for the RA's contentions regarding the September 2, 1999 submission by PSE&G, the due process argument was addressed in IV D, above. As noted there, the RA did have a week to question the "methodology" that PSE&G relied on in the submission when calculating the "expected net present value savings and rate reductions resulting from issuance of the Transition bonds." The RA does not now question any specific aspect of that methodology, but rather the inadequate time it had to respond to it. The RA had an opportunity, albeit a very limited one, to review and to question the methodology. It was not absolutely denied notice or an opportunity to be heard.

Contrary to NJBUS's position, PSE&G's partial funding of the 5% August 1999 rate reduction through a 1% prepayment of anticipated securitization savings does not violate N.J.S.A. 48:3-52(i), which requires that the rate reductions resulting from issuance of the transition bonds "shall be made no later than the date on which the transition bond charge . . . becomes effective." As noted, the transition bonds have not yet been issued, but some anticipated savings have already been passed through to customers, per order of the BPU. The BPU accepted the 1% prepayment proposal in Stipulation I without comment in the Final Decision; in its brief the BPU said that its decision on this matter "reflects a proper balancing of the competing interests, and represents a pragmatic recognition that application of these funds are reasonably necessary to achieve [the Act's] mandated 5% immediate reduction, from rates previously adjudged by the BPU to be just and reasonable." NJBUS offers no justification for disturbing this aspect of the BPU's decision.


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