August 9, 2007
IN THE MATTER OF ATLANTIC CITY ELECTRIC COMPANY D/B/A CONECTIV POWER DELIVERY FOR APPROVAL OF AMENDMENTS TO ITS TARIFF TO PROVIDE FOR AN INCREASE IN RATES FOR ELECTRIC SERVICE
On appeal from the New Jersey Board of Public Utilities, ER02080510.
NOT FOR PUBLICATION WITHOUT THE APPROVAL OF THE APPELLATE DIVISION
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.
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.
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 few customers were being served by any means other than BGS. Elliott maintains that ACEC could not have anticipated this.
ACEC argued that the Ratepayer Advocate had failed to identify any particular capacity purchase by ACEC that was imprudent when it was made, based on the then-available information. Although ACEC recognized that it had failed to file a timely RFP with the BPU by September 15, 1999, it argued that, due to the uncertainty regarding both price and volume, it was not possible to issue an RFP in late 1999 that would have resulted in a long-term contract. The data necessary for evaluating such long-term contracts, asserted ACEC, was either scarce or non-existent. Hence, Crane's testimony regarding the possibility of long-term contracts was treated by Elliott as speculative at best. In addition, Elliott claimed that any long-term contract entered into in 1999 would have carried a substantial risk premium built into the price.
As for Crane's allegation that ACEC had missed out on earlier opportunities to "hedge" before the summer of 2001, Elliott claimed that the purchases ACEC had made pursuant to RFP-III and RFP-IV operated, in effect, as hedges against rising prices in the fall of 2000 and spring of 2001, respectively. Elliott asserted that the prices and quantities of supply associated with the summer of 2001 could not have been foreseen with any degree of clarity back in 1999 and 2000. Additionally, Elliott noted that Crane had failed to identify some other source of on-peak summer energy in 2001 that ACEC could have acquired.
With respect to ACEC's acceptance of 200, rather than 400, MWs of capacity in RFP-III, Elliott claimed that decision was reasonable because ACEC knew there would be other future opportunities to bid for more capacity. In fact, ACEC subsequently purchased 800 MWs of capacity pursuant to RFP-IV.
8. The BPU Staff's Additional Recommendations and Analysis In a brief filed by the BPU Staff with the Board after the close of the evidentiary hearings, the Staff endeavored to quantify the cost impacts of the deficiencies in ACEC's procurement practices. Specifically, the BPU Staff's written analysis priced ACEC's "'discretionary purchases' [i.e.,] nonNUG or other long-term contractual purchases) at the estimated price of energy and capacity that would have been incurred if the same energy and capacity had been purchased from PJM during the first three years of the [T]ransition [P]eriod." Based upon that analysis, the BPU Staff concluded that the actual cost of ACEC's purchases was $518.8 million, as compared to $353.3 million if it had purchased from PJM. This amounts to a difference of $165.5 million. Hence, "[o]n a unit cost basis, the average actual cost of [ACEC's] discretionary purchases was $72.38 per Mwh, as compared to $49.32 Mwh if purchased from PJM." The BPU Staff then compared these costs to those incurred by Jersey Central Power & Light (JCP&L) and Rockland Electric Company (RECO) for the same period. Those other electric companies had costs of $49.68/Mwh and $55.38/Mwh, respectively.
9. The ALJ's Findings and Initial Decision
The ALJ was persuaded that no actions or omissions of ACEC rose to the level of "imprudence," although some were "not reasonable." According to the ALJ:
A review of the record as a whole supports a conclusion that, for whatever reasons, [ACEC] did not initially take steps that would have been reasonable at the time to gain better control over the entire procurement process. The record contains no persuasive rationale for [ACEC's] failure to initially assemble an experienced BGS supply organization, in terms of both personnel and research. Compounding the situation was the fact that the staff assigned to energy procurement were not performing such functions on a full-time basis. Such was especially important in light of the fact that there was uncertainty regarding competition, PJM rules and markets, the level of BGS customers, over time, and timing of divest[iture]. As the Auditors testified, reasonable and prudent management would have been to assure that the decision-makers were the most qualified to make important supply decisions, especially given the uncertainty at the time in question and the new environment of deregulation per se.
In addition, the ALJ found scant evidence in the record that ACEC had considered entering into parting contracts or other financial instruments for hedging purposes.
The ALJ then addressed ACEC's failure to submit an RFP plan to the BPU by the mandated September 15, 1999 deadline, or to provide the Board with reasons for its failure to do so. Even though there was no clear nexus between this failure and any costs the Ratepayer Advocate sought to disallow, the ALJ concluded that it was "incumbent on [ACEC] to show that its procurement practices, overall, were reasonable, not for other parties to establish a direct causation link, which may be impossible." Moreover, the ALJ found that ACEC's "repeated hesitancies to take action without prior BPU approval also reflects a maladaption to the regulatory environment in New Jersey." Nevertheless, the ALJ agreed with the BPU auditors that such flaws in RFP-I and RFP-II did not directly impact ACEC's energy and capacity costs.
Also of particular concern to the ALJ was ACEC's decision to purchase only 200 MWs of capacity because of its concerns about the Board's negative reaction to the responses the ACEC had received to RFP-III. The ALJ found that there should be a disallowance for this decision, in the amount of $6.1 million, as recommended by the BPU auditors.
As part of her assessment, the ALJ specifically rejected the BPU Staff's analysis that had compared costs under ACEC's BGS supply contracts to the costs to purchase supply from the PJM. The ALJ did so for two reasons. First, as a procedural matter, the Staff's analysis had not been presented at the hearings through oral testimony. In addition, the ALJ found the Staff's analysis flawed on its merits because it was purportedly based on an "assumption of large amounts of BGS supply purchased at available PJM rates in a market that would not have been affected by large-scale purchases." The ALJ also rejected the Staff's analysis because it "utilized PJM price data from outside [the ACEC's] zone in PJM."
10. The Board's Final Decision
The BPU adopted the ALJ's recommendation to make the $6.1 million adjustment, but it declined the judge's recommendation to reject all of the other disallowances proposed by the Ratepayer Advocate and by the intervenors.
The Board first noted that its approvals of ACEC's requests to issue RFPs during the Transition Period were not approvals of the associated costs. Rather, its approvals were predicated on the clear understanding that the recovery of related costs would be subject to review of their reasonableness and prudence.
Assessing ACEC's conduct more harshly than the ALJ, the Board found that management of the RFP process during the first three years of the Transition Period was "seriously deficient." Even within the framework of the four RFPs that ACEC did issue, the Board considered its decisions regarding how much capacity and energy to accept, and for how long, as sufficiently deficient to warrant further disallowances.
The Board specifically found that long-term parting contracts, or contracts otherwise tailored to the needs of the seller, could have been executed "at attractive ('below market') rates at that time [as] borne out by the experience of the State's two other similarly situated utilities, JCP&L and RECO." When compared to the parting contracts negotiated by JCP&L and RECO, the Board found that ACEC's own performance "fell far short." However, the Board agreed with ACEC's decision to reject the use of financial hedging instruments during the Transition Period, finding that this decision was reasonable and prudent. On this score, the Board noted the poor results achieved by RECO with its hedges and the limited use of comparable financial instruments by JCP&L.
Additionally, the Board determined that the ALJ had erred in rejecting the BPU Staff's post-hearing analysis of ACEC's reliance on the PJM market, because it had been presented through briefs instead of through witness testimony. The Board observed that the Staff's role in a rate proceeding is to analyze the evidence submitted by the parties and to make recommendations based on that analysis, and that there was no obligation by the Staff to present direct evidence before taking a position.
According to the Board:
While the Board recognize[d] that that there are inherent differences among utilities, and while not suggesting that ACE[C] should have relied solely on the PJM spot market, nonetheless, we believe that the magnitude of ACE[C]'s excessive costs relative to the costs achieved by the State's two other similarly-situated utilities who utilized parting contracts, appears unreasonable, and indicative of the shortcomings in [ACEC's]
BGS procurement identified by the parties herein.
Further, the Board rejected ACEC's claim that it was inappropriate to compare its costs to those of the other two utilities because of differences in their service territories or because of differences in the portion of the BGS load being served by their purchases. Even doing the comparison in a manner that the ACEC suggested, the Board found that ACEC's costs for its contractual purchases had substantially exceeded at least those of JCP&L.
In sum, with respect to ACEC's purchases in July and August 2001, the Board found that the Ratepayer Advocate's proposal to cap the costs of those purchases, which accounted for the bulk of ACEC's BGS deferral, was reasonable. The Board therefore accepted a proposed adjustment of $25.527 million to ACEC's deferred BGS balance.
B. Disallowance for BGS Excess Capacity Purchases
The next major issue concerned the question of whether a disallowance was warranted for ACEC's purchases of BGS excess capacity. According to Elliott, the uncertainty of the divestiture date for ACEC's fossil and nuclear plants factored into the RFP process because, once such divestiture occurred, the ACEC would need additional supply. Because the fossil units were not divested at the time that ACEC had originally anticipated, it wound up with excess capacity. However, ACEC sold the excess capacity to the PJM market, and the revenues from those sales were credited against ACEC's deferrals.
1. The Auditors' Analysis
On this issue, Barrington found that ACEC was a net seller of energy during the RFP period, meaning that it had more energy than it needed to serve its BGS load. Barrington also found that ACEC had sold its excess capacity and that the revenues from these sales were properly credited to the BGS.
2. The Ratepayer Advocate's Analysis
Crane, the Ratepayer Advocate's witness, offered a different assessment. She noted that ACEC's capacity costs increased significantly in June 2001, corresponding to the capacity contracts it entered into in the spring of 2001. Consequently, ACEC failed to sell its excess capacity at rates sufficient to cover the costs incurred to acquire that capacity. Crane thus recommended a reduction of $3.7 million to ACEC's deferred balance because ACEC had failed to use its best efforts to sell this capacity at the highest possible price.
Crane also felt the ratepayers should be held harmless from the negative impacts of selling excess capacity below cost. Her calculation on this matter was based on "the difference between the monthly average capacity costs incurred by [ACEC] and the amount received for this capacity through capacity sales."*fn8
According to Crane, the majority of the recommended disallowances were for the months of November 2001 through May 2002. For example, for January 2002, Crane recommended a disallowance of $210,857, based on the difference between ACEC's average cost of capacity for that month and the amount it received in capacity that month, even though ACEC made a profit off of what it had bought from and sold to Exelon that month. The same was true for the months of February and March 2002. Crane conceded that ACEC had actually incurred the costs it claimed for the months in question and that it had credited the revenues it received for these months against its costs.
3. ACEC's Response to the Auditors and the Ratepayer Advocate
In response, Elliott contended that Crane's proposal was "a purely mathematical exercise" and that she had failed to look at when contracts to buy or sell were executed or what the market prices were at the time the decisions were made. Elliott identified three main variables affecting ACEC's decisions with respect to purchasing and selling capacity.
First, Elliott contended that the PJM was constantly changing the rules, thereby causing extreme swings in capacity prices. Second, the third-party load was constantly changing. Elliott explained in this regard that when retail choice first started, ACEC assumed that about fifteen to twenty percent of its load would be supplied by third-party suppliers. However, by the summer of 2001, as capacity costs skyrocketed, the third-party supplier load shrank and customers returned to ACEC, thereby creating an increased need for capacity in ACEC's portfolio. Elliott maintained that ACEC had no control over when these customers would return and no control over PJM rule changes.
Third, Elliott noted the Board's failure in the spring of 2001 to approve ACEC's sale of its fossil units to NRG Energy, Inc. ("NRG"). This inaction, Elliott stated, caused ACEC to end up with excess capacity to be resold. According to Elliott, ACEC had an executed contract to sell its fossil units to NRG. That contract allowed NRG to cancel the sale if regulatory approval was not obtained by a certain date. At its meeting on January 31, 2002, the Board orally approved the sale. However, because the Board did not issue an order until twenty days later, NRG was allowed to, and did in fact, exercise its option to terminate the contract.*fn9
Elliott contended that ACEC could not have foreseen this particular sequence of events and that, after it received notice of NRG's cancellation, it "participated in the PJM capacity markets attempting to sell the excess capacity. All revenue from the sales [was] being credited to the BGS account."
On cross-examination, Elliott was asked whether the excess capacity ACEC then found itself with in 2002 was sold at a loss or a profit. He maintained that whenever ACEC made decisions on capacity, it would sell capacity based on market conditions at the time, and that "to have a profit, you have to have a cost associated." Without reference to a fixed date, Elliott could not state anything more than "there were times we sold it at a profit and other times we sold it at a loss."
4. The ALJ's Findings
On this subject, the ALJ found that there was nothing in the record to support a conclusion that ACEC was responsible for the delay in the Board's approval of the NRG contract. The ALJ did recognize that after ACEC found itself in a situation of excess capacity, it could not provide specific information regarding whether sales at that point had been conducted at a profit or a loss. Nevertheless, the ALJ concluded that ACEC should not be penalized for the fact that NRG terminated the contract. The judge noted that ACEC had appropriately included the revenues from the sales of its excess capacity as credits to deferral costs.
The ALJ also agreed with ACEC that the Ratepayer Advocate's mathematical analysis on this issue was flawed because "if [ACEC] purchased capacity under a 12-month contract at the prevailing market price and sold excess capacity for one month, also at the prevailing market price, [the] Ratepayer Advocate's approach would disallow the costs of that portion of the 12- month contract price in excess of the sales price." In sum, Crane's analysis had focused on discrete transactions, instead of looking at the overall reasonableness of ACEC's actions. "In effect, Crane's adjustment was based on an inferred theory that if revenues received in a particular month for a capacity sale did not cover the capacity expenses incurred in a month for an equivalent amount of capacity bought, there should be a disallowance." The ALJ agreed that this was, as Elliott contended, a "purely mathematical exercise."
5. The Board's Determination
The Board's Final Decision rejected the ALJ's recommendation on the disallowance and instead adopted the Ratepayer Advocate's recommended disallowance. The Board found that ACEC's use of the Exelon purchases and sales in any one month to illustrate flaws in Crane's analysis was "facially simplistic, and not particularly meaningful for the purpose at hand." As the Board noted, "[n]o rational seller would contract to sell capacity at a given price in a given month and simultaneously agree to purchase the same amount of capacity in that same month at a higher price." The Board was thus unable to link or match any sale to any purchase in any given month for the purpose of imputing profits or losses. It instead found that Crane's analysis, using an average of all purchases, struck a reasonable balance.
In addition, the Board rejected the argument that its rejection of the sale of ACEC's fossil units to NRG had been responsible for all of the recommended May 2002 disallowance for excess capacity. Instead, the Board found that "the impact of the failed NRG sale appears to have been substantially less than [ACEC] suggests." Moreover, the Board found that an analysis of the May 2002 capacity sales raised a question as to whether ACEC got the best price it could have for these sales.
Accordingly, the Board accepted the Ratepayer Advocate's recommended disallowance of $3.375 million of ACEC's BGS deferred balance arising from its excess capacity purchases.
C. Above-Market Costs of TBD Fossil Units
The record also reflects a dispute over the above-market costs of TBD fossil units held by ACEC. These claimed costs relate to the MTC portion of ACEC's deferred balance. The proofs on this issue were as follows.
1. The Evidence
According to Crane, the largest component of ACEC's MTC was the above-market costs associated with its TBD generation. ACEC decided to purchase eighty percent of its BGS requirements for the fourth year of the Transition Period (beginning August 1, 2002) through the Board-sponsored statewide auction. This figure was chosen because ACEC had assumed that the NUG contracts would provide the remaining twenty percent. That is, it assumed that its fossil units would be divested by this time and that any BGS supply not provided by its NUG contracts would be provided through the auction. Because the divestiture did not happen, ACEC still had generating units that were contributing twenty percent of supply, over and above its BGS requirements.
Articulating the Ratepayer Advocate's perspective, Crane asserted that, "to the extent that the revenue requirement associated with the to-be-divested generation exceeds the revenues received from the sale of the excess power, ratepayers are being asked to pay higher rates . . . ." The Ratepayer Advocate therefore recommended that the deferral for the fourth year "be reduced to eliminate the above-market revenue requirement associated with to-be-divested generation costs that exceed the amount associated with stranded costs of the facilities." Accordingly, Crane "reduced the above-market tobe-divested monthly generation costs included in the MTC to $1,084,000, which is [ACEC's] estimate of the monthly amount associated with stranded costs." She did not eliminate the revenue associated with the sales from these TBD units.
In response to the Ratepayer Advocate's recommended disallowance, Elliott focused on the Board's failure to timely approve the sale of the fossil units to NUG. He contended that ACEC's ratepayers were not being penalized by the retention of these units because the BGS auction prices reflected market conditions at the time and because the ratepayers were being credited with the revenue from any sales of capacity in the PJM market. The BPU Staff agreed with Elliott on this issue.
2. The ALJ's Determination
Concerning these points, the ALJ noted that Crane "did not calculate that [excess BGS supply] existed, nor the revenue associated with the sales from the facilities in question . . . ." Moreover, ratepayers were credited with the results of sales of excess capacity. Sales of any capacity and energy thus were reflected in deferral amounts.
Moreover, according to the ALJ, the excess capacity held by ACEC was largely related to the failure of the NRG contract to be consummated, which the ALJ did not attribute to any unreasonableness on ACEC's part. In addition, the retention of these units arguably benefited ratepayers over the prior two years because their operating costs were lower than, or at least in line with, alternative supply sources on the open market.
3. The BPU's Determination
In its own ruling, the Board agreed on this issue with the ALJ and with BPU Staff. The Board determined that because it had approved the NRG sale at its January 31, 2002 public meeting, ACEC had a reasonable basis to assume, shortly thereafter on February 15, 2002 when it contracted for its BGS supply for the final year of the Transition Period, that the fossil units would be divested by the time its fourth year auction power began flowing on August 1, 2002. The Board also found that, following the termination of the NRG sale on April 1, 2002, ACEC acted expeditiously to resell the units and initiated a second auction process in May 2002. The Board therefore affirmed the ALJ's initial decision on the excess fossil capacity issue, rejecting the $29.569 million MTC disallowance proposed by the Ratepayer Advocate.
D. Interest on the LEAC Balance
Another contested issue involved the starting point of the BGS deferral for purposes of calculating interest. According to the Board's final restructuring order, ACEC's Levelized Energy Adjustment Clause ("LEAC") over-collection balance as of August 1, 1999, was to be used as the starting balance for its BGS deferral. The order did not state specifically whether interest on this balance should be calculated monthly or annually.
Rather, the order stated that the methodology should be similar to what ACEC had utilized in the past for its LEAC rate.
ACEC's opening LEAC balance was an over-recovery of $50,002,000. That amount did not include interest. The starting point for this balance was May 1997, the date on which the Board last reviewed the reconciliation of the LEAC revenues to the LEAC costs and had approved the under-recovery. With respect to interest on this balance, ACEC's methodology was as follows:
In determining whether or not interest should be applied to the balance, [ACEC] calculated a monthly interest amount each month from June 1997 through August 1999 and then netted the monthly interest to determine the net interest payable to ratepayers. From June 1997 to August 1998, [ACEC's] LEAC was under-collected and therefore interest was negative in these months. In subsequent months, [ACEC's] LEAC balance was over-collected and interest was owed to ratepayers. Since [ACEC] netted out all of the months from June 1997 through July 1999, the net result of [ACEC's] interest calculation is that no interest is due to ratepayers.
According to Herbert Chalk, an expert witness*fn10 ACEC presented on this subject, the last time ACEC filed for a change in its LEAC was in September 1998. That filing had included a "true-up" for the period June 1997 to September 1998. Although those proposed changes were never implemented, nobody had objected to the extended true-up period proposed in the filing. The average cumulative balance during each of those months was negative. That is, the averages of each monthly under-recovery and over-recovery, were all negative for that period. Hence, if interest had been calculated for any twelve-month period during that time, the result would have been that no interest would be due to the ratepayers.
The Ratepayer Advocate disagreed with Chalk's methodology because, according to Crane, the LEAC methodology included an "annual true-up, not a true-up over a multi-year period." Interest was to be calculated each month and then summed up at the end of the LEAC year. If the total at the end of the LEAC year required interest to be paid to ratepayers, that interest, in Crane's view, should be credited. If interest was owed to the utility, the utility would make appropriate accounting entries. Thus, interest should be examined "in discrete 12-month intervals to determine if [ACEC] owes ratepayers interest on any LEAC over-collections."
Accordingly, Crane recalculated the interest for the twelve-month periods ending May 1998 and May 1999.*fn11 Using this analysis, Crane opined that ACEC did not owe any interest to ratepayers for the period ending May 1998, but ACEC did owe them interest in the amount of $1,306,000 for the period ending May 1999. In addition, Crane figured that $687,000 was due ratepayers for June and July 1999, bringing the total proposed adjustment to the LEAC credit balance to $1,993,000.
The ALJ recommended that the Ratepayer Advocate's interest adjustments not be adopted. The judge applied the pertinent LEAC regulation, N.J.A.C. 14:3-13.4(a), which contemplates monthly calculations of interest, and concluded that ACEC's determination of final interest as of the end of the period covered by its last LEAC was consistent with this regulation. The ALJ was persuaded by ACEC's argument that the Ratepayer Advocate's recommended adjustment would deny ACEC "any recognition of interest expense incurred over an arbitrarily selected 12-month period to purchase fuel and power used, but not yet paid for by customers . . . ." The Board agreed with the ALJ's recommendation.
E. The "Net-of-Tax" Calculation
The parties also contested whether or not interest on the under-recovered balance should be calculated on the "net-of-tax" balance. Previously, for purposes of LEAC, ACEC had calculated interest on the cumulative balance, not the net-of-tax balance.
According to Chalk, cumulative interest on ACEC's deferred balance at the end of the Transition Period would be $8.9 million. If the net-of-tax deferred balance was used, interest would be $5.26 million. Chalk stated that when ACEC booked its deferral expenses on the under-recovery, it set up deferred taxes that would be reversed when it collected back those revenues from the customers. The operating income impact of the deferrals during the Transition Period was thus mitigated by the income tax savings associated with the expense deduction for tax purposes. As ACEC collected those monies back in the future, it would be getting revenues in excess of expenses and would have to pay taxes on those revenues. Hence, the issue here was one of timing. According to Chalk, the tax expense that ACEC incurred would be offset by the tax benefit it received.
Conversely, the Ratepayer Advocate contended that, in calculating the interest that accrued on the deferral balance during the Transition Period, it was necessary to reduce the amount of the deferral by the income tax savings associated with the expenses that gave rise to the deferral. According to Crane, "[w]hen these costs were incurred, they resulted in an expense deduction for income tax purposes." Specifically, "the operating income impact upon [ACEC] was mitigated by the income tax savings associated with this expense deduction." Hence, this "net-of-tax basis should be used as the base to which interest is applied." Crane believed that this approach was consistent with prior Board policy. She asserted:
When the revenues associated with recovery of this deferral are collected from ratepayers in the future, it will be necessary to provide for a recovery of the income taxes that will be due on those revenues. Therefore, the net-of-tax deferral will eventually be grossed-up in some manner to account for the fact that [ACEC] will incur an income tax expense at the time that it recovers its deferred costs from ratepayers.
The ALJ disagreed. The judge found that the pertinent LEAC regulation did not, on its face, require that interest on LEAC balances be calculated using net-of-tax balances. The ALJ found this interpretation was consistent with ACEC's past practices, and that adoption of a net-of-tax approach would make the calculations more complicated and could result in subsequent rate changes. The judge therefore found that it was reasonable not to require a calculation based on net-of-tax balances.
As a threshold procedural finding, the Board noted that "the lack of specificity on this implementation detail" in its final restructuring order did not preclude its review of the issue. Substantively, the Board rejected the ALJ's conclusion on this issue, and directed ACEC to "recalculate the interest accrued on its post August 1, 1999 deferred balances on a net-of tax basis, i.e., to deduct deferred income taxes associated with both the deferred costs and the deferred interest from the balance on which the interest is accrued."
The appeal and the cross-appeals now before us ensued.
Our analysis commences with a recognition of the governing scope of review. An appellate court must defer to an agency's interpretation of a statute it is charged with enforcing, provided that the interpretation is not "plainly unreasonable." In re Pub. Serv. Elec. & Gas Co.'s Rate Unbundling, Stranded Costs & Restructuring Filings, 167 N.J. 377, 384 cert. denied, 534 U.S. 813, 122 S.Ct. 37, 151 L.Ed. 2d 11 (2001). With respect to an agency's factual findings, the appellate court's function is not to substitute its judgment for that of the agency, particularly when that judgment reflects agency expertise. Ibid.
The BPU is vested with broad discretion in the exercise of its rate-making authority, which is a legislative, not judicial, function. Ibid.; In re Jersey Cent. Power & Light Co., 85 N.J. 520, 526-27 (1981); In re Pub. Serv. Elec. & Gas Co., 304 N.J. Super. 247, 264 (App. Div.), certif. denied, 152 N.J. 12 (1997). "Accordingly, upon the exercise of its broad authority and the conduct of appropriate proceedings, 'the Board's rulings are entitled to presumptive validity and will not be disturbed unless we find a lack of "reasonable support in the evidence."'" In re Pub. Serv. Elec. & Gas Co.'s Rate Unbundling, Stranded Costs & Restructuring Filings, supra, 167 N.J. at 385 (citations omitted); accord, In re Jersey Cent. Power & Light Co., supra,
85 N.J. at 527; In re Pub. Serv. Elec. & Gas Co., supra, 304 N.J. Super. at 264. Complex valuation formulas and accounting concepts are the type of decisions best left to the agency's expertise. In re Pub. Serv. Elec. & Gas. Co's Rate Unbundling, Stranded Costs & Restructuring Filings, supra, 167 N.J. at 392.
In addition, particular deference to an administrative agency "is especially appropriate when new and innovative legislation is being put into practice," In re Adopted Amendments to N.J.A.C. 7:7A-2.4, 365 N.J. Super. 255, 264 (App. Div. 2003), or when the agency "has been delegated discretion to determine the specialized and technical procedures for its tasks." In re Freshwater Wetlands Gen. Permits, 372 N.J. Super. 578, 593 (App. Div. 2004). These principles especially apply to the present context involving a new statute, the EDECA, and our State's transition from the traditional market for electric power to a new market accommodating consumer choice.
"A public utility has a constitutional and statutory right to a reasonable rate of return." In re Valley Rd. Sewerage Co., 285 N.J. Super. 202, 208 (App. Div. 1995), aff'd, 154 N.J. 224 (1998). It is also recognized that the public should not be required "'to pay for the consequences of lazy or inefficient management,'" and that good management, honest stewardship, and diligence is expected and required. Id. at 210 (quoting In re Bd.'s Investigation of Tel. Cos., 66 N.J. 476, 495, 502-03 (1975)). Hence, the Board must balance the burden on ratepayers with the interests of a utility's investors. In re Jersey Cent. Power & Light Co., supra, 85 N.J. at 531. In this regard, the Board may come to an "innovative and a mutually fair interim solution to a critical problem . . . ." Id. at 532.
We will not, however, sustain action by an administrative agency that is arbitrary, capricious, or unreasonable, that is beyond the agency's delegated powers, or that is not supported by substantial evidence in the record. In re N.J. Am. Water Co., Inc., 169 N.J. 181, 188 (2001); In re Musick, 143 N.J. 206, 216 (1996). In addition, the deferential review standard may be lessened where a disputed decision does not involve the agency's area of expertise. In re New Jersey Am. Water Co., supra, 169 N.J. at 195.
With these deferential review standards in mind, we now turn to the discrete issues presented on appeal.
A. Disallowance for ACEC's Purchases in Summer of 2001
ACEC contends that the Board erred in accepting the Ratepayer Advocate's recommended disallowance of $25.527 million of purchase power costs incurred in the months of July and August 2001. We discern no reversible error, however, in the Board's determination.
This particular disallowance, which by far was the largest component of the Board's overall disallowance, was computed by utilizing a cap on the recoverable expenses for July and August 2001. The Board essentially accepted the Ratepayer Advocate's arguments that ACEC had failed to prepare adequately for the price spikes in these months by failing back in 1999 to enter into long-term contracts, by failing to negotiate parting contracts, and by otherwise failing to utilize financial mechanisms, or hedges, to avoid the price spikes.
ACEC emphasizes that, at each step of the procurement process during the first three years of the Transition Period, it kept the Board apprised of the approach it was taking and that the Board implicitly or explicitly approved ACEC's conduct. While this may be true, ACEC overlooks the fact that both N.J.S.A. 48:3-57 and the final restructuring order gave the Board the ultimate right to determine, at the time ACEC sought to recover its deferred expenses for BGS, whether these expenses had been reasonably and prudently incurred. Every order that the Board issued during the first three years of the Transition Period made it clear that such a review was going to take place and that ACEC would have to defend its expenses at an administrative hearing. Hence, the Board was not in any way estopped from challenging these expenses.
ACEC also contends that the Board's decision was not supported by the evidence presented, and was arbitrary and capricious. ACEC maintains that the Board improperly looked at its conduct with the benefit of hindsight, rather than assessing what was "reasonable and prudent" at the time each decision was made. We are not persuaded that this claim warrants any alteration of the Board's decision.
The record does contain some evidence tending to support ACEC's argument that, in the first three years following the introduction of retail competition, the market was extremely volatile and uncertain. That volatility surely made it difficult for ACEC to predict with clarity how many customers would need BGS and how many would choose third-party suppliers. Even so, the Board reasonably relied on the other proofs presented, mostly through the testimony of Crane, the Ratepayer Advocate's expert, that showed that ACEC had mismanaged the early months of the Transition Period. There is substantial record evidence that these early missteps essentially dictated ACEC's difficulties in the months and years to follow, most dramatically in the summer of 2001.
We appreciate that the BPU auditors could not quantify any particular cost associated with ACEC's failure to have its first RFP filed by September 15, 1999. However, the Ratepayer Advocate's expert Crane testified that, had ACEC acted expeditiously, as required by the final restructuring order, it could have had a long-term contract in place by the summer of 2001. At the very least, ACEC could have avoided finding itself in the position of having to purchase energy during the high peak months of July and August 200l. In essence, ACEC's poor management of the RFP process and its failures to prepare for long-term needs resulted in its vulnerability to market spikes in the summer of 2001. The Board had reasonable grounds to not impose all of the adverse consequences on the utility's customers.
Although the Board's decision on this subject involved some degree of hindsight assessment, that was the very nature of its task here. The deferral process itself, sanctioned by our Supreme Court in In re Pub. Serv. Elec. & Gas Co.'s Rate Unbundling, Stranded Costs & Restructuring Filings, 330 N.J. Super. 65, 114 (App. Div. 2000), aff'd, 167 N.J. 377, cert. denied, 534 U.S. 813, 122 S.Ct. 37, 151 L.Ed. 2d 11 (2001) required the agency to look at the utility's past conduct and to try to assess, in retrospect, whether that conduct was reasonable and prudent at the time.
Given our deferential standard of review, we sustain the BPU's decision with respect to its disallowance for purchases ACEC made in the summer of 2001. The Board made its decision only after a reasoned and careful analysis of the entire record, which was quite voluminous. Moreover, its expertise in this matter cannot be overlooked. Although we recognize that the ALJ came to the opposite conclusion on this issue, we are reviewing the Board's decision, which has both support in the record and a reasoned basis. New Jersey Dep't of Pub. Advocate v. New Jersey Bd. of Pub. Utils., 189 N.J. Super. 491, 503, 507 (App. Div. 1983); In re Suspension or Revocation of License of Silberman, 169 N.J. Super. 243, 255-56 (App. Div. 1979), aff'd o.b., 84 N.J. 303 (1980).
We also find no reversible error in the Board's failure to rebut each and every point of the ALJ's decision on this subject. Although an administrative agency should identify any disagreement with an ALJ that was crucial to its decision and should set forth the basis for that disagreement, the agency does not have to discuss in detail every point of disagreement or every evidentiary item that the ALJ analyzed. New Jersey Dep't of Pub. Advocate, supra, 189 N.J. Super. at 501, 505-06.
As another aspect of its arguments, ACEC contends that the Board improperly relied on an after-the-fact analysis of the market prepared by its Staff, not as part of the record before the ALJ, but in a subsequent brief supplied to the ALJ. As we noted, the ALJ rejected the Staff's analysis, both on the merits, and on the procedural ground that it had not been presented by the way of oral testimony. The Board, however, found no immutable obligation on the part of the BPU Staff to present evidence before the ALJ prior to taking a position on an issue. We agree.
To be sure, N.J.S.A. 52:14B-9 does require that the findings of fact in contested cases be based "exclusively on the evidence and on matters officially noticed." N.J.S.A. 52:14B-9(f). The agency must thus limit its consideration to the record made before the ALJ, which also includes the ALJ's recommended report and decision. New Jersey Dep't of Pub. Advocate, supra, 189 N.J. Super. at 500.
Nevertheless, ACEC's complaints about the BPU Staff's post-hearing submission must fail. In In re Pub. Serv. Elec. & Gas Co.'s Rate Unbundling, Stranded Costs & Restructuring Filings, supra, 330 N.J. Super. at 115, calculations had been prepared by independent auditors hired by BPU Staff after the ALJ had issued his initial decision, in which the judge stated that it was impossible to determine a specific "stranded cost" amount for the Board's consideration. The Attorney General had circulated the auditors' report to all the parties. Ibid. In its final decision, the BPU adopted the ALJ's decision and accepted as reasonable the auditor's calculations, with a minor modification. Id. at 116.
Although the auditors' report in PSE&G had not been formally admitted into evidence at the hearing before the ALJ, we noted that the parties had been given copies of it, knew that it had been prepared to help the BPU quantify its analysis, and had the opportunity to respond to it. Id. at 117. Thus, we concluded BPU's reliance on the report was not a procedural irregularity that denied the other parties due process. Ibid.*fn12
The same result should obtain here.
In conclusion, we reject ACEC's argument regarding the Board's $25.527 million disallowance to its BGS deferred balance.
B. Excess Capacity Purchases
ACEC next contends that the Board's disallowance of $3.375 million for the purchases of excess capacity was not supported by the evidence. ACEC also argues that the Board's determination on this issue was based on a "flawed analysis of the market." Neither of these arguments is persuasive.
We are mindful there was some evidence in the record that could have supported a determination by the Board to reject this particular disallowance. In particular, we are aware that the Ratepayer Advocate conceded that ACEC had actually incurred the costs in question and that ACEC had credited the revenues it received for the months in question against those specific costs. Moreover, we recognize that the Ratepayer Advocate was not contending that ACEC should have sold more capacity than it did, that it should have sold it at different times, or that the selling or purchasing prices were not consistent with market conditions.
Nevertheless, the Board ultimately concluded that the Ratepayer Advocate's analysis, which rested upon an average of all of ACEC's purchases, struck a reasonable balance. We cannot say that the Board's decision in this regard was arbitrary or capricious. The cost data that it relied upon was part of the evidential record. The cost averaging approach it adopted was reasonable, if not absolutely required.
In sum, the Board carefully sifted through the record, considered the positions of all the parties, and weighed the merits and demerits of the ALJ's initial decision on excess capacity before rejecting it. We are not persuaded that this particular assessment should be set aside, particularly given the Board's regulatory expertise.
C. ACEC's Purchase of Insufficient Capacity
ACEC further contends that the Board erred in adopting the disallowance recommended by the ALJ for $6.1 million in excess costs that were incurred due to the purchase of insufficient capacity in RFP-III. We disagree. This particular disallowance was not only recommended by the Ratepayer Advocate, but was also recommended by the BPU auditors and by the ALJ in her initial decision.
ACEC's primary argument on appeal concerning this issue is that the Board based its decision on an "after-the-fact justification," rather than on facts known to ACEC at the time it made its decision in RFP-III to purchase only 200 MWs, rather than 400 MWs, of capacity. However, the very nature of a proceeding to recover a deferral balance, following an audit that ACEC should have anticipated, necessitates a certain amount of hindsight analysis. Although the Board recognized that the standard it should use to evaluate ACEC was that of reasonableness and prudence at the time the various decisions were made, the Board was not required to ignore the events that subsequently arose. These events simply provided further context for the evaluative process.
We therefore concur with the harmonious findings of the ALJ and the Board on this issue, and sustain them.
D. ACEC's Failure to Consummate the Sale of TBD Fossil Generation Assets
In its cross-appeal, the Ratepayer Advocate contends that the Board erred in allowing ACEC to pass onto ratepayers the costs of its failure to sell its TBD fossil units. According to the Ratepayer Advocate,
[i]t was the utility's management and employees that had the background and the knowledge necessary to make the decision to sell the fossil units and to eventually consummate the deal. If management was not up to the task of bringing the deal to a close, the utility has only itself to blame.
This position overlooks the contrary findings of both the ALJ and the Board that ACEC did not act unreasonably in failing to consummate the fossil unit sale. Rather, the record supports their shared conclusion that the potential sale collapsed when the Board failed to issue a timely written approval to ACEC, after having indicated at its meeting that such approval would be given. ACEC thus justifiably relied on the Board's approval when it determined its BGS supply for the fourth year of the Transition Period. The ALJ also found, and the Board agreed, that the retention of these fossil units arguably benefited ratepayers, because their operating costs were lower than, or at least in line with, alternative supply sources on the open market.
None of this was arbitrary, capricious, or unreasonable, or lacking in evidential support. We therefore sustain the agency's determination.
E. The "Net-of-Tax" Interest Calculation
Additionally, ACEC contends that the Board erred in changing the method it used for calculating interest, and that the alleged switch to the "net-of-tax" method unfairly penalized ACEC by an amount of $7.7 million. Although this matter is one that is subject to reasonable debate, we nonetheless sustain the Board's interest calculation.
As we have noted, the Board's final restructuring order stated that, in setting the annual level of charges for BGS during the Transition Period, ACEC "will utilize a methodology similar to that currently used for setting its Energy Adjustment clause charges." With respect to interest calculation, the levelized energy adjustment clause, also known as the LEAC, is governed by N.J.A.C. 14:3-13.4. Contrary to ACEC's argument, nothing in that regulation specifically addresses the net-of-tax issue. Moreover, as the Board properly notes, the final restructuring order referred only to the rate recovery mechanism and was silent with respect to the tax aspects of the balance to which interest was to be applied. Hence, the Board's net-of-tax methodology in its final decision did not conflict with the pertinent administrative rules or with its prior order.
ACEC also argues that, in the past, the Board customarily has calculated interest on LEAC balances for ACEC on the full deferred balance, not the net-of-tax balance. However, in its final decision, the Board stated that the net-of-tax methodology was, in fact, in accordance with its prior orders dealing with the deferred balances of the State's other public utilities.
We shall not disturb the Board's determination on this issue. The Board's choice of methodology for calculating interest rested squarely within its area of expertise. Its methodology, which it has applied to other electric companies, fosters uniformity for all utility ratepayers. Moreover, as ACEC's expert Chalk himself admitted, the issue here was essentially one of timing because the net financial effect upon ACEC ultimately would be the same. The determination is affirmed.
F. Multi-Year Calculation on the LEAC Balance
In its cross-appeal on interest issues, the Ratepayer Advocate contends that the Board erred in adopting ACEC's decision to commence the calculation of interest on the LEAC balance as of July 31, 1999. That chosen date served as the starting point for ACEC's BGS deferred balance. We perceive no reversible error in the Board's decision to accept that starting point.
Prior to the enactment of EDECA, the LEAC was a widely used and judicially accepted rate-making mechanism to recover certain components of fuel costs incurred by utilities. In re Petition of Atl. City Elec. Co., 310 N.J. Super. 357, 362 (App. Div.), certif. denied, 155 N.J. 590 (1998). It was designed to permit a utility "'to include in rates initial estimates as to future fuel costs and to make subsequent periodic adjustments to reflect actual costs when ascertained.'" Ibid. (quoting In re Application of Rockland Elec. Co., 231 N.J. Super. 478, 484 (App. Div.), certif. denied, 117 N.J. 129 (1989)). The LEAC was based on "estimated prospective 12-month energy costs." Ibid. (quoting In re Petition of Jersey Cent. Power & Light Co., supra, 85 N.J. at 524).
There is no dispute that, pursuant to the Board's final restructuring order here, ACEC was required to credit its LEAC over-recovered balance, as of July 31, 1999, to its starting BGS deferred balance. The balance that ACEC employed did not include any interest because ACEC had utilized a twenty-six-month "true-up" period (i.e., from June 1997 to August 1999) to calculate whether its balance was positive or negative for the purposes of the interest calculation. The Ratepayer Advocate contends that this approach violated N.J.A.C. 14:3-13.4(a). We disagree.
The applicable regulation, N.J.A.C. 14:3-13.4, has several facets. First, the regulation generally provides that the "clause cost adjustment will be effective on a 12-month basis unless otherwise specified by the Board within the context of an appropriate rate proceeding." N.J.A.C. 14:3-13.4(a). Additionally, "[t]he difference between actual clause costs and the utility's recovery amount of the base clause cost and the clause cost adjustment charge shall be determined monthly." N.J.A.C. 14:3-13.4(b). "Interest shall be applied monthly to the average monthly cumulative deferred balance, positive or negative, from the beginning to the end of the clause period." N.J.A.C. 14:3-13.4(c). Further, "[m]onthly interest on negative deferred balances . . . shall be netted against monthly interest on positive deferred balances . . . for the clause period." N.J.A.C. 14:3-13.4(d). "A cumulative net positive interest balance at the end of the clause period is owed to customers" and "[a] cumulative net negative interest balance shall be zeroed out at the end of the clause period." N.J.A.C. 14:3-13.4(e). Lastly, "[t]he sum of the calculated monthly interests shall be added to the overrecovery balance or subtracted from the underrecovery balance at the end of the clause period." N.J.A.C. 14:3-13.4(f).
According to the Ratepayer Advocate, by using a full twenty-six-month period instead of the twelve-month period called for by subsection (a) of the regulation, ACEC "carried over the net negative interest balance from the first clause period and used [it] to offset the cumulative net positive interest balance at the end of the second clause period." Although the Ratepayer Advocate recognizes that the Board may specify a period other than twelve months in a rate proceeding, N.J.A.C. 14:3-13.4(a), it argues that the Board here improperly allowed ACEC to deviate from the twelve-month period "without the protection of a rate proceeding."
Nonetheless, the ALJ accepted ACEC's methodology, utilizing the twenty-six-month timeframe, because she was persuaded that ACEC otherwise would be denied any recognition of interest expense incurred over an "arbitrarily selected 12-month period" to purchase energy that had not yet been paid for by its customers. The Board adopted this finding and recommendation.
We are not convinced by the Ratepayer Advocate's argument that the litigation before the ALJ and the Board in this case fails to qualify, in effect, as an "appropriate rate proceeding" for the purposes of N.J.A.C. 14:3-13.4(a). The regulatory subsection provides the Board with the authority and flexibility it may need to modify the period to be used for "truing-up" interest on LEAC balances. That authority was reasonably exercised here, where the LEAC balance for ACEC was not being used as it was originally contemplated, but was merely serving as the starting point for a similar balance necessitated by the conversion to retail competition for power under the EDECA. The pendency of ACEC's base rate filing while the present litigation over its deferred balances was ongoing does not alter our view of the flexibility inherent in the regulation.
Although the Board's decision would have been enhanced by a more explicit discussion about why it was deviating from the usual twelve-month period provided in N.J.A.C. 14:3-13.4(a), ultimately this decision amounts to a policy choice that the Board made in implementing "new and innovative legislation." In re Adopted Amendments to N.J.A.C. 7:7A-2.4, supra, 365 N.J. Super. at 264. As such, it is entitled to our considerable deference. We sustain it as a reasonable determination, and not beyond the ambit of the applicable rules.
In sum, we affirm the Board's substantive determinations in their entirety. Having considered this technically-complex record as a whole, we are satisfied that the Board's painstaking decisions on the various issues and sub-issues find "reasonable support in the evidence." In re Pub. Serv. Elec. & Gas Co.'s Rate Unbundling, Stranded Costs & Restructuring Filings, supra, 167 N.J. at 385. We are likewise satisfied that the Board's individualized rulings, while open to reasonable disagreement, are neither arbitrary nor capricious, and are not contrary to the governing law. Aqua Beach Condominium Ass'n. v. Dep't of Cmty. Affairs, 186 N.J. 5, 16 (2006). Overall, the Board acted judiciously in disallowing about one-sixth of the $176 million that ACEC had claimed in deferred balances, adopting some of the cuts recommended by the Ratepayer Advocate while rejecting others.
We consequently affirm the BPU's substantive application of its considerable expertise in rendering a detailed and well-reasoned decision in the context of a major regulatory transition to a new consumer-choice-based market for electric power in our State.
We now turn to a procedural issue raised by Cogentrix in its cross-appeal. Cogentrix was the general partner in two electric cogeneration facilities with contracts to supply ACEC with electric capacity.
Cogentrix argues that the Board erred in denying its motion to intervene in this matter. Specifically, Cogentrix maintains that the Independent Energy Producers of New Jersey (IEPNJ), which did have intervenor status in the case, did not adequately represent the interests of Cogentrix. Cogentrix also asserts that there was no risk of undue delay had Cogentrix been allowed to intervene and that the public interest favored Cogentrix's intervention.
By way of background, Cogentrix moved to intervene before the Board in October 2002. Cogentrix sought to protect its economic interests in two cogeneration facilities located in the ACEC service area that provided ACEC with electric energy and capacity, pursuant to long-term power purchase agreements. The two cogeneration facilities were Chambers Cogeneration Limited Partnership ("Chambers") and Logan Generating Company, L.P. ("Logan"). Through subsidiaries, Cogentrix, a non-public corporation based in North Carolina, held ownership interests in two Delaware-based partnerships with respect to Chambers and Logan.
Cogentrix argued that ACEC's petition before the Board involved several issues that would "directly or indirectly, implicate Chambers and Logan, their respective [power purchase agreements] and, thereby, the economic interest of Cogentrix and its investors." Specifically, ACEC's petition had sought to recover funds that included costs associated with NUGs such as Chambers and Logan. ACEC's petition had also defended its efforts to renegotiate, restructure or terminate certain power purchase agreements with NUGs. Cogentrix proposed to intervene on a limited basis, confined to issues related to or derived from implementation of those power purchase agreements.
ACEC opposed Cogentrix's intervention. ACEC noted that IEPNJ, a trade association created to advance the common interests of the State's generators of electric power, was already an intervenor in the case. Consequently, ACEC contended that any intervention by Cogentrix based on its contractual interests with ACEC would likely be duplicative of the arguments set forth by the IEPNJ. Moreover, ACEC asserted that intervention was not necessary to advance the principle that ACEC was entitled to the full recovery of its costs under its NUG contracts.
In November 2002, the ALJ requested Cogentrix to clarify
(1) whether Chambers and Logan were members of IEPNJ; (2) whether Cogentrix, Chambers, and/or Logan had contracts with ACEC; and (3) the nature of Cogentrix's economic and property interests in Chambers and Logan. In response, Cogentrix submitted a certification of Thomas J. Bonner, its Vice President of Operations. According to Bonner, neither Chambers nor Logan was a member of IEPNJ. In addition, Cogentrix itself was not a member of IEPNJ and did not authorize IEPNJ to represent its interests in this proceeding. However, the ALJ was also informed that PG&E/National Energy Group (PG&E), a partner in the entities that own and operate Chambers and Logan, was indeed a member of IEPNJ.
Both Chambers and Logan had thirty-year power purchase agreements with ACEC. These contracts were worth $170 million per year in anticipated revenues, to be paid by ACEC through funds collected from its ratepayers through the NNC. Through its subsidiaries, Cogentrix owned equity interests equal to ten percent of Chambers' partnership and contract and fifty percent of Logan's partnership and contract. According to Bonner, NUG power production was utilized in BGS, and the NNC component of ACEC's deferred balance, which ACEC sought to recover, "means Chambers and Logan."
On December 9, 2002, the ALJ issued an order denying Cogentrix's motion to intervene. According to the ALJ, Cogentrix had not demonstrated a substantial, specific, or direct interest in the current matter, and the terms of Chambers' and Logan's purchase power agreements with ACEC would not be altered in this case. To the extent that Cogentrix did have an arguable interest in the matter by virtue of its being a general partner with Chambers and Logan, the ALJ ruled that its interest would be adequately protected, at least indirectly, because PG&E, a partial owner of Chambers and Logan, was a member of IEPNJ. Granting Cogentrix's motion to intervene thus "would not add measurably and constructively to the scope of the current matter and raise[d] the prospect of confusion and undue delay." However, the ALJ granted Cogentrix so-called "participant" status, limited to the right to file post-hearing briefs and exceptions to the initial decision.
Cogentrix filed an emergent interlocutory motion to the Board to appeal this decision. In opposing the motion, ACEC argued that Cogentrix was not a majority owner of either Chambers or Logan and was not responsible for the management of either entity. In addition, under its contracts, ACEC was required to deal only with PG&E, who was a member of IEPNJ. Moreover, the deferral before the ALJ and ultimately the Board proceeding was not going to determine how much was paid under the NUG contracts or whether the contracts were being performed. Finally, none of the activities under either contract involved any action by Cogentrix.
At its January 8, 2003 meeting, the Board denied Cogentrix's motion for interlocutory relief. It ruled that Cogentrix was not a customer of ACEC and instead was "merely a passive investor" in two generation plants. As such, the Board agreed with the ALJ that awarding participant status in the case would be sufficient to protect Cogentrix's interests. Cogentrix's moved for reconsideration of the Board's ruling, which was denied.*fn13
Pursuant to N.J.A.C. 1:1-16.1(a), any entity not initially a party to an administrative proceeding "who has a statutory right to intervene or who will be substantially, specifically and directly affected by the outcome of a contested case, may on motion, seek leave to intervene." The standards involve multiple considerations, all to be weighed by the ALJ presiding over the case:
In ruling upon a motion to intervene, the [ALJ] shall take into consideration 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).]
In contrast to intervention, a motion for leave to participate may be made by any entity "with a significant interest in the outcome of a case." N.J.A.C. 1:1-16.6(a). The ALJ shall consider "whether the participant's interest is likely to add constructively to the case without causing undue delay or confusion." N.J.A.C. 1:1-16.6(b).
Although we disagree with the Board's contention that Cogentrix's appeal of the denial of intervention should be rejected as moot, we do concur with the Board and with the ALJ that Cogentrix's interests in this case were quite attenuated. Any financial relief Cogentrix sought was addressed in the subsequent rate base proceeding in which it was allowed to intervene, at least on discrete issues, and from which it apparently did not appeal. The NUG contracts of concern to Cogentrix were never litigated in the deferral balance proceeding. Cogentrix's efforts to compel, in effect, an advisory opinion on those contracts were justifiably rejected.
See Crescent Park Tenants Ass'n v. Realty Eq. Corp. of N.Y., 58 N.J. 98, 107 (1971) (disfavoring advisory opinions).
In sum, Cogentrix lacked a sufficient stake or interest in the discrete issues before the Board so as to have required intervenor status, rather than participant status, in this case. Accordingly, we sustain the Board's decision adopting the ALJ's denial of Cogentrix's motion to intervene.