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In re Atlantic City Electric Co.

August 9, 2007


On appeal from the New Jersey Board of Public Utilities, ER02080510.

Per curiam.


Submitted December 20, 2006

Before Judges A. A. Rodríguez, Sabatino and Lyons.

Atlantic City Electric Company ("ACEC") appeals from those portions of a July 8, 2004 order of the New Jersey Board of Public Utilities ("the BPU" or "the Board") that precluded ACEC from recouping certain deferred costs it had incurred during a transition period when, pursuant to the Electric Discount and Energy Competition Act, N.J.S.A. 48:3-49 to -98 ("EDECA" or "the Act"), the electric utility industry was being deregulated and restructured.

The primary issue on appeal is whether there was sufficient credible evidence in the record to support the Board's conclusion that certain of ACEC's deferred costs were not "reasonable and prudently incurred," as required by N.J.S.A. 48:3-57(e). The Ratepayer Advocate cross-appeals from other portions of the Board's order that allowed ACEC to recoup certain other expenses. Additionally, Cogentrix Energy Inc. ("Cogentrix") cross-appeals from the Board's denial of its motion to intervene.

We affirm.


To appreciate the factual record and the issues on appeal, a discussion of their statutory and regulatory context is in order. The EDECA, which was enacted on February 9, 1999, established a framework and time schedule for the deregulation and restructuring of electric utilities in New Jersey. Retail competition was set to begin on August 1, 1999. N.J.S.A. 48:3-53a. The Act mandated a five percent rate reduction by August 1, 1999, and at least a ten percent reduction within three years thereafter. N.J.S.A. 48:3-52d(2).

Pursuant to the EDECA, electric utility companies such as ACEC had to unbundle their rates and separately identify charges for discrete services. N.J.S.A. 48:3-52a. They also had to provide "basic generation service" ("BGS") for customers who did not choose an alternate power supplier, N.J.S.A. 48:3-57, and were permitted to recover "all reasonable and prudently incurred costs" incurred in the provision of such services. N.J.S.A. 48:3-57e.

The Act also provided for the implementation of a "Market Transition Charge" ("MTC") to allow the utilities to recover an approved level of "stranded costs" resulting from the restructuring. N.J.S.A. 48:3-61. Such stranded costs were defined as the amounts by which the net cost of a utility's generating assets or power purchase commitments exceeded the market value of such assets or commitments. N.J.S.A. 48:3-51.

ACEC is engaged in the generation, transmission, distribution, and sale of electric energy to residential, commercial, and industrial customers within the southern portion of New Jersey. In June 1999 two proposed stipulations of settlement were filed with the BPU with respect to ACEC's restructuring proceedings. On July 15, 1999, the BPU issued a Summary Restructuring Order concerning ACEC, and on March 30, 2001, it issued a Final Restructuring Order.

Pursuant to these orders, the Board designated August 1, 1999 through July 31, 2003 as the "Transition Period," in accordance with N.J.S.A. 48:3-51. During the Transition Period, ACEC was to apply both non-utility generation ("NUG") power and to-be-divested ("TBD") owned generation power (prior to the closure of the sale of the generation assets) towards its BGS supply requirement.

For the first three years of that Transition Period, i.e., August 1, 1999 through July 31, 2002, ACEC was to solicit requests for proposal ("RFPs") for the provision of wholesale supply for BGS in twelve-month pricing cycles, "or such other cycles as [ACEC] deems necessary or prudent." ACEC was to submit its plans for the RFP process to the Board by September 15, 1999, and was to commence the RFP process "as soon as practicable after such date and approval of the plan by the BPU, with the goal of concluding such process and entering into a contract for BGS supply by December 15, 1999." Any contracts for the provision of BGS had to be presented to and approved by the Board.

The Board decided that ACEC would be entitled to recover its reasonable and prudently-incurred BGS costs, its reasonable and prudently-incurred restructuring-related costs (through the MTC), its above-market NUG costs (through the net non-utility generation charge, or "NNC"), as well as other costs not relevant to this appeal. To the extent ACEC might have to defer recovery of some portion of these costs in order to achieve or sustain rate reductions during the Transition Period, these deferred costs, together with a return on the unrecovered balance, would be recoverable at the end of the Transition Period after being audited by the Board. ACEC's pursuit of a fuller recovery of such deferred costs than the amount allowed by the Board is the central subject matter of this appeal.

Significant to this appeal, the Board directed ACEC to mitigate price risks in providing BGS for the first three years of the Transition Period. The Board also encouraged ACEC to use hedging mechanisms and other financial instruments, as well as the negotiation of "parting contracts"*fn1 to obtain energy and capacity for the provision of BGS. These measures were all authorized in an effort to decrease ratepayer exposure to price spikes and to price volatility.

According to the Board, the State's four major electric utility companies, including ACEC, "accumulated significant levels of restructuring-related deferred balances during the Transition Period." Consequently, on July 31, 2002, Governor McGreevey signed Executive Order No. 25, convening a Deferred Balances Task Force to address the reasons why those deferred balances were accumulated, what mitigation steps the utilities had taken to reduce the deferred balances, and how they should be addressed to protect the interests of the ratepayers. In a report issued on August 30, 2002, the Task Force recommended that evidentiary hearings be held and an independent audit be performed. That recommendation was advanced to ensure that the utility companies bore and satisfied the burden of proof for recovering such deferred balances.

Meanwhile, on August 1, 2002, ACEC filed a petition with the BPU to set rates for August 1, 2003, and to recover its deferred balance for costs deferred during the Transition Period. ACEC projected that its deferred balance at the end of the Transition Period, including interest, would equal $176,400,000. This amount was comprised of a claimed under-recovery of BGS of $49,053,000, an under-recovery of NNC of $26,951,000, an under-recovery of MTC of $114,737,000, and an over-recovery of a so-called societal benefit charge ("SBC") of $24,508,000. Interest on these sums was calculated by ACEC at $10,205,000. The net impact on rates, if ACEC's petition were approved in full, would have been about 8.4%.

ACEC's petition was transmitted to the Office of Administrative Law for hearing as a contested case. The Administrative Law Judge (ALJ) granted motions for intervention by the Independent Energy Producers of New Jersey and the New Jersey Large Energy Users Coalition, as well as motions for participation by Rockland Energy Company and PPL Energy Plus, LLC. However, the ALJ denied Cogentrix's motion to intervene but granted it what is described as "participant status."*fn2

On various dates in February 2003 the ALJ held evidentiary hearings on the deferred balance portion of ACEC's petition. The parties pre-filed the direct testimony of their respective witnesses. Because much of what was recommended by the ALJ in her Initial Decision and decided by the Board in its Final Decision has not been appealed by the parties, we shall confine our summary of the testimony to the proofs germane to the substantive issues before us.

Among the many documents moved into evidence before the ALJ was the Audit of Deferred Balances for ACEC. The audit had been prepared by the two independent auditing firms, Mitchell & Titus, LLP ("Mitchell"), and Barrington-Wellesley Group, Inc. ("Barrington"). Mitchell and Barrington had been retained by the BPU to provide it with certified opinions as to whether ACEC's deferred balances as of July 31, 2003, were "accurately calculated, correctly recorded, fairly stated in all material respects, and in compliance with Board Orders."*fn3 Their audit also included a so-called prudency review of ACEC's practices in BGS procurement for the first three years of the Transition Period ("Phase I"), and its mitigation efforts with respect to above-market NUG contract costs during the full Transition Period. Following their review, the auditors recommended an aggregate adjustment to ACEC's deferred balance of $4.5 million.

The ALJ issued her 135-page initial decision on June 2, 2003, granting some, but not all, of ACEC's deferred balance claims. Subsequently, the ALJ's decision and additional submissions were considered by the Board.

On July 21, 2003, the Board voted to adopt the recommendations of BPU Staff with respect to ACEC's deferred balances. In doing so, the Board granted some, but not all, of the additional adjustments sought by the Ratepayer Advocate but not recommended by the ALJ, thereby reducing the rate impact of ACEC's petition from 8.4% to about 7.8%. The Board consequently issued a summary order on July 31, 2003, and its 134-page final decision and order on July 8, 2004.

We discuss, in the pages that follow, specific aspects of those respective determinations by the ALJ and the Board, and the associated proofs on those discrete issues. The five issues concern: (a) ACEC's procurement of BGS supply; (b) disallowance for certain "excess capacity" purchases; (c) above-market costs of fossil units held by ACEC; (d) interest on the so-called LEAC balance; and (e) the "net-of-tax" calculation.

A. ACEC's Procurement of BGS Supply

As his testimony in the OAL reflected, Jerry A. Elliott,*fn4

Vice President of Transmission and Distribution Reliability for ACEC, was placed in charge of procuring BGS supply for ACEC in late 2000. Prior to that time, ACEC's portfolio manager for BGS had been an individual who, according to Barrington, had no experience in energy supply. Instead, the expertise of Elliott's predecessor was in the development of RFPs.

In January 2000 ACEC hired the Wayfinder firm, an independent consultant, to help it develop RFPs for a "full requirements"*fn5 BGS supply for the period from January 1, 2000, to July 31, 2002. Wayfinder was not asked to provide expertise in supply procurement. Rather, its role was to receive and codify the bidder responses to the RFPs to avoid any conflict of interest on ACEC's part.

1. RFP-I

ACEC's first RFP was issued on October 9, 1999. It was circulated to eighty-nine potential bidders, and was for a term extending from January 2000 to July 31, 2002. ACEC received no responses to that initial RFP. According to Elliott, ACEC learned that suppliers had no interest in responding due to the uncertainty regarding the potential size of the BGS load. This uncertainty arose because (1) retail choice by energy consumers was just beginning in New Jersey, (2) divestiture dates for fossil and nuclear plants were uncertain, and (3) the potential for buyouts of ACEC's NUG contracts. In addition, the risk of volume fluctuation made it difficult for suppliers to hedge their price risk.

After its first RFP drew no bidders, ACEC then decided to solicit the provision of a fixed supply of energy and capacity through May 31, 2000. Accordingly, ACEC revised its RFP and sent it to the same eighty-nine bidders. This time, ACEC received only two responses. As Elliott recounted, ACEC decided not to enter into contracts with either of those bidders because it concluded that the Pennsylvania-New Jersey-Maryland power pool ("PJM") would be more likely than the bidders to furnish ACEC with power at lower costs.


ACEC next developed a two-tiered RFP (RFP-II),*fn6 requesting bids for 300 and 350 megawatts (MWs) of capacity and energy for on- and off-peak periods for June through August 2000. On March 14, 2000, ACEC petitioned the Board to approve that RFP. Notably, this was the first RFP submitted to the Board by ACEC, despite the fact that the Board's final restructuring order had required ACEC to submit its RFP by September 15, 1999. The Board approved the RFP on May 15, 2000, but ordered ACEC to issue an addendum to it for an alternative 300 MWs of supply for a twelve-month period.

In its May 15, 2000 order, the BPU indicated that it was concerned with the impact that ACEC's handling of the matter would have on its deferred cost balance and, ultimately, on customer rates. The BPU warned ACEC that it did not have an absolute right to recover these costs and chastised the ACEC for unilaterally opting to purchase capacity and energy on the open market rather than using a competitive process. The Board refused to comply with ACEC's request to "pre-approve" any particular negotiated agreement, and it reminded ACEC that it would have to demonstrate the reasonableness or prudence of its procurement prices in a future deferral proceeding.

Around this time, ACEC replaced Wayfinder with a different consulting company, Lexecon, which had expertise in supply procurement. Lexecon assisted ACEC in evaluating the bids received from RFP-II. Acting on Lexecon's advice, ACEC ultimately rejected all of the bids, finding that they were not competitive. Instead, ACEC continued to make use of the PJM-administered markets.


In the late summer of 2000, ACEC changed its procurement strategy to a flexible "portfolio" approach. This approach was a combination of long-term, medium-term, and short-term purchases in order to diversify the sources of supply and reduce price volatility. ACEC accordingly issued another RFP (RFP-III), soliciting bids for the period January 2001 to July 2002 for 400 MWs of capacity and on-peak energy. In response to RFP-III, ACEC received only one bid for capacity but nine energy bids. ACEC thereafter awarded an energy contract to the lowest bidder. However, in light of the fact that there was only one bid for capacity, ACEC decided to reduce the amount of the award on that item from 400 MWs to 200 MWs. According to Elliott, ACEC was concerned that only one bid would not be deemed a truly competitive process by the BPU.


In the spring of 2001, ACEC issued its final request (RFPIV), seeking capacity bids for July and August 2001 and for July 2002. Although the Board approved this RFP, it cautioned ACEC that it would have to demonstrate, in a future proceeding, the reasonableness and prudence of its decisions and of its flexible portfolio approach. The Board also cautioned ACEC to exercise appropriate diligence in entering into contracts for BGS that it anticipated would be needed to replace the capacity and energy of its divested facilities.

ACEC ultimately entered into one on-peak energy contract and two capacity contracts as a result of RFP-IV. Beginning in September 2002, all capacity and energy not supplied by ACEC's own facilities or NUG contracts have been provided through a statewide auction process, i.e., not through the RFP process.

5. The BPU Auditors' Findings and Recommendations

The BPU's auditors found that, for the first three years of the Transition Period, ACEC did not have a full understanding of what the BGS supply process would entail, and that it had failed to take adequate steps to establish an experienced BGS supply organization. The auditors underscored that it was not until the summer of 2000 that ACEC hired a consultant able to provide ACEC with the required level of expertise and guidance.

The auditors concluded that ACEC's actions with respect to RFP-I and RFP-II were flawed, both in the development of the RFPs and in its analysis of the decision-making process. Specifically, Barrington found that, with respect to RFP-I, ACEC mistakenly compared the two bids it received to each other, but not to PJM market prices. The lack of Board pre-approval also influenced ACEC's decision not to implement negotiated agreements with either of the two bidders. In addition, ACEC's determination of the amount of energy and capacity required and its forecast of the BGS load during the RFP-I period was not determined to be accurate.

With respect to RFP-II, the auditors found that ACEC failed to elicit any acceptable bids, had changed the requirements after the RFP was issued, had continued to seek pre-approval from the Board for any awarded contracts, and had accepted Lexecon's recommendation to reject all bids on the basis that projected market prices would be lower. Consequently, with respect to both RFP-I and RFP-II, ACEC had unnecessarily expended time and effort to develop and solicit bids that did not result in any energy purchases.

However, the auditors were unable to quantify these unnecessary expenses. They concluded that the flaws in RFP-I did not appear to have had a direct impact on BGS energy and capacity costs, and that it was not clear that there was a cost impact from the deficiencies in RFP-II. Hence, they were unable to conclude whether a different process would have resulted in acceptable bids.

With respect to RFP-III, the auditors found that it was imprudent for ACEC to have accepted only half of the 400 MW capacity requested, based on the receipt of only one bid. They concluded that this decision resulted in a $6.1 million increase in BGS costs. As a result, the auditors recommended that ACEC's deferral balance be adjusted accordingly.

Finally, the auditors found that ACEC's actions regarding RFP-IV were reasonable.

6. The Ratepayer Advocate's Recommendations

Andrea Crane testified about these BGS supply issues as an expert witness on behalf of the Ratepayer Advocate. Crane is the vice president of a financial consulting firm specializing in utility regulation.*fn7 She was retained by the Ratepayer Advocate to review ACEC's entire deferred balance filing.

According to Crane, the energy purchases made by ACEC in July and August 2001 were largely responsible for its overall BGS deferral. That is, ACEC's claimed BGS deferral for the entire Transition Period was a net figure over $49 million, and the deferrals in these two months alone accounted for more than $78 million in that calculation. Crane asserted that if ACEC had better managed its costs during these two particular months, its entire BGS deferral might have been avoided.

Crane conceded that the PJM also experienced high locational marginal prices during July and August 2001.

However, Crane opined that, if ACEC had entered into long-term contracts and had put such contracts into place starting in December 1999, as anticipated in the Board's final restructuring order, ACEC might have avoided the adverse effects of these high price spikes in July and August 2001. Alternatively, she contended that ACEC could have entered into hedging agreements to protect against excessive price spikes. As a result of the ACEC's actions, it was, in Crane's words, "at the mercy of the market" in July and August 2001.

Consequently, Crane recommended that ACEC's purchases for these two months be set at rates equivalent to the average of overall BGS cost paid for TBD generation and for NUG. By Crane's analysis, this would result in reductions to the BGS deferral balance for these two months of $25.527 million.

On cross-examination, Crane conceded that no one knew for sure what would have happened if ACEC had submitted its first RFP to the Board by September 15, 1999, as required by the restructuring order. Nor can we know with certainty what would have ensued if ACEC had solicited bids based on an annual period, or if it had been more aggressive with regard to hedging opportunities. Even so, Crane believed that ACEC should be held accountable for not following through on these possibilities. She noted that, by comparison, Public Service Electric & Gas (PSE&G), another New Jersey energy supplier, had managed to avoid a BGS deferral for the first three years of the Transition Period.

When counsel for ACEC asked her what it could have done to avoid its BGS deferral, Crane responded:

I don't know that there's any one answer as to what you could have done. I'm not absolutely sure that if you had taken any other avenues, your costs would be lower, frankly, but I do think that there were lots of things that you could have done that you didn't do, and as a result, when July and August rolled around in 2001, and PJM prices spiked, you were in trouble and were left with 78 million dollars of deferral in those two months. [Emphasis added.]

Crane did not make any specific recommendations as to what ACEC should have done about this issue. She noted that there were many factors that resulted in the problems in July and August 2001. She did point out, however, that an RFP issued in the spring of 2000, seeking a contract for a twelve-month period (i.e., RFP-II), would have resulted in the contract's expiration right before the peak summer months in 2001, which generally is "not a good time to be going out and trying to acquire power . . . ." Crane similarly criticized RFP-III for being filed in November 2000 and covering a period from January 2001 through July 2002, thus ending in the middle of the summer of 2002.

However, she conceded that the contract period in RFP-III at least did span the entire summer of 2001.

Crane also admitted that if a contract had been signed in December 1999, as envisioned by the Board's restructuring order, it would not have covered the summer of 2001, but she argued that it "might have" put ACEC on a whole different cycle that would have enabled it to develop relationships with suppliers that would have been beneficial to ACEC in the summer of 2001. In her words, it was "the path not taken[,] so to speak."

Crane's analysis took into account the entire three-year Transition Period, and whether ACEC's actions were reasonable from beginning to end. Although certain actions taken by ACEC in July 2001 might have been reasonable, given the position in which ACEC found itself at that point, Crane's criticism was with what ACEC did to cause itself to be in that position.

7. ACEC's Responses to the Auditors and the Ratepayer Advocate

According to ACEC's expert Elliott, Crane's opinions failed to take sufficient note of the chaotic market conditions that generally persisted during the relevant time periods, and the fact that the energy market in New Jersey was evolving in 1999 and 2000. In the fall of 1999, ACEC had operated on the assumption that the percentage of the load to be served by third-party suppliers would increase. Contrary to those expectations, by the summer of 2001, relatively ...

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