Case ID: pa-commw_166/html/0413-01.html
Source: Caselaw Access Project
Author: {"author": "PELLEGRINI, Judge.", "license": "Public Domain", "url": "https://static.case.law/"}
Date Created: 2024-08-24T03:29:51.129683

648 A.2d 63
    PENNSYLVANIA ELECTRIC COMPANY, Petitioner, v. PENNSYLVANIA PUBLIC UTILITY COMMISSION, Respondent. CAMBRIA PARTNERS, Petitioner, v. PENNSYLVANIA PUBLIC UTILITY COMMISSION, Respondent.
    Commonwealth Court of Pennsylvania.
    Argued June 9, 1994.
    Decided Aug. 4, 1994.
    Application for Reconsideration Granted in Part and Denied in Part Oct. 7, 1994.
    
      Alan Michael Seltzer, for petitioner PA Elec. Co.
    William T. Hawke, for petitioner Cambria Partners.
    Lee E. Morrison, Asst. Counsel, for respondent.
    Clifford B. Levine, for intervenors American Power Corp. and CMS Generation Co.
    
      Tanya J. McCloskey, Asst. Consumer Advocate, for intervenor Office of Consumer Advocate.
    Before PELLEGRINI and FRIEDMAN, JJ., and RODGERS, Senior Judge.
   PELLEGRINI, Judge.

The Pennsylvania Electric Company (PECO) and Cambria Partners (Cambria) have filed consolidated appeals from an order of the Pennsylvania Public Utility Commission (PUC) directing PECO to enter into two separate agreements with qualifying facility (QF) developers LG & E Energy Systems, Inc. (LG & E) and American Power Corporation and CMS Generation Company (American/CMS) for the purchase of electrical power from their respective proposed QFs.

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This appeal arises as a result of petitions filed by three QF developers to have the PUC order PECO to enter into power purchase agreements with them under the provisions of PURPA. Each involves a long and involved history, but as to the issues relevant to this appeal, they can be summarized as follows.

LG & E requested the PUC to order PECO to enter into a power purchase agreement for 80 megawatts (MW) of capacity and energy from its QF to be located at the International Paper Company’s mill in Erie, Pennsylvania. LG & E contended that PECO had a need to purchase at least 80 MW of capacity by relying on its 1990 Annual Resource Planning Report (ARP) in which it indicated that it had a need for 100 MW of additional peak capacity by 1995, and about 600 MW of new base load capacity to be phased in as three 200 MW blocks during the 2000-2009 timeframe. The PUC found that it had an effective filing date of March 21, 1991.

American/CMS petitioned to have the PUC order PECO to purchase power from a 300 MW QF which it proposed to build at the Juniata Locomotive Repair Shop owned by Consolidated Rail Corporation located in Blair County, Pennsylvania. While it had engaged in discussions with PECO to purchase power, it contended that PECO had refused to enter into a purchase power agreement as required by PURPA regulations. It requested that the PUC order PECO to enter into a 30-year contract for the purchase of capacity and electricity from that project.

Cambria also filed a petition requesting that the PUC direct PECO to enter into a long-term purchase power agreement with it from its proposed QF to be located in New Germany, Cambria County, Pennsylvania. The project would provide a total of 350 MW, consisting of a 200 MW indigenous coal-fired component and a 150 MW natural gas-fired component. Cambria alleged that based on PECO’s 1990 ARP, PECO would require approximately 700 MW of new capacity from 1995-2000, broken down by 100 MW of peak capacity in 1995-96 and three 200 MW increments of base load capacity from 2000-2009. Cambria further alleged that it first contacted PECO in December of 1987, had ongoing communications through January of 1991 regarding PECO’s purchase of power from the Cambria project, and ultimately made an offer to PECO on April 30, 1990, to sell it capacity and energy. However, it contended that PECO ultimately refused to sign a long-term agreement because it stated it did not need any of the capacity offered by Cambria.

PECO filed individual answers to each of the petitions opposing the projects because it alleged it only needed, at most, 100 MW of peak capacity during 1995 based upon its 1990 ARP filed with the PUC, and 200 MW of base load capacity by the year 2000. It further alleged that based on its 1991 ARP filed with the PUC on May 1, 1991, it had no need for any additional capacity until 1999.

Extensive hearings were held before an ALJ concerning PECO’s need for additional capacity, the issue of the proposed QFs’ priority, and the calculation of avoided costs. In the ALJ’s decision, he first determined that PECO’s 1991 ARP would be used to determine PECO’s need for capacity. Rejecting PECO’s suggestion that it should be allowed to define its own need for service, he then determined that based on the 1991 ARP, PECO had a clear need for approximately 100 MW during 1997 (or at least 80 MW of capacity). As to PECO’s avoided cost, the ALJ based the avoided cost on PECO’s projected installation of a 125 MW combined cycle plant during 1999 as stated in its 1991 ARP, rather than on a coal plant proxy as urged by American/CMS and Cambria. He found that PECO’s cost to produce the same amount of power would be 8.467 cents per kilowatt hour (kWh) on a “rolled in” 30-year levelized basis, with a 1997 in-service date. He did not address any capacity needs past 1997 or provide an explanation as to why future needs were not addressed.

Finally, he concluded that LG & E should be first in line to develop its project and contract -with PECO, relying primarily on the “first to file” rule and the plant size, noting that LG & E filed its petition with the PUC on March 21, 1991, while American/CMS filed on April 5, 1991, and Cambria filed on April 27, 1991. The ALJ did, however, also consider the time a bona fide offer was made to PECO; the benefits of the project, economic and otherwise; plant size, and fitness/viability of the QF developer. Notably, he made no priority determinations as to .contracts with American/CMS or Cambria. Exceptions to the ALJ’s recommended decision were filed by all of the parties.

Contrary to the ALJ’s findings and recommendation, the PUC determined by order dated November 17, 1992, that PECO had an additional need for up to 169 MW of capacity by the year 2000 rather than the ALJ’s finding of 100 MW by 1997, an amount sufficient to require two cpntracts for 80 MW of capacity each. It then determined that the contracts would be awarded to LG & E and American/CMS. While declining to adopt the ALJ’s pure “first to file” rule, it determined that priority of contracts would be decided after two preliminary criteria were met: 1) that the proposed QF demonstrated it was somewhat developed rather than merely a concept; and 2) the proposed QF had contacted the utility and attempted to reach an agreement. After these criteria were met, it would then consider the experience of the proposed developers, the viability and benefits of the proposed QF, the quality of existing utility service to the site, project size and time of initiation of proceedings. The PUC agreed with the ALJ that the 1991 ARP would be the starting point for determining the appropriate timing related to avoided cost and need because those factors had to be determined within a reasonable proximity to the date the proceedings were initiated; however, it was also required by FERC and PUC regulations to examine capacity needs for a ten-year period from that starting date.

The PUC further determined that the pricing for the sale of capacity and energy to PECO would be as set forth in the offers made by LG & E and American/CMS with 20 to 30 year contracts, as long as their price offers were at or below avoided costs determined by use of a coal plant proxy rather than PECO’s projected installation of a 125 MW combined cycle plant during 1999 as used by the ALJ. The PUC explained that because PECO “has not committed to sufficient plant to meet its reserve margin obligation and maintain adequate system reliability,” 52 Pa.Code § 57.34(c)(4)(iii) required that a coal proxy be utilized to determine construction costs of a new coal plant in calculating capacity credit. Finally, the PUC stated that in the event LG & E and/or American/CMS declined to enter into a contract with PECO, PECO was required to offer Cambria the opportunity to enter into such a contract for the balance of its capacity needs as determined by this order. It then remanded the case to the ALJ for the limited purpose of considering the calculations of avoided costs using a coal plant proxy with an on-line date of 1997 and a 25 to 33 year useful life.

Pursuant to the PUC’s order, the ALJ requested the parties to submit calculations on avoided costs using a coal plant proxy with an on-line date of 1997 and a 25 to 33 year useful life. Upon review of those submissions, the ALJ issued a decision on January 19, 1993, recommending to the PUC that it use the calculations submitted by American/CMS and the Office of Consumer Advocate (OCA) with certain modifications, ultimately resulting in an avoided cost being calculated based on a 33-year calculation using a coal plant size of 400 MW.

The PUC adopted the ALJ’s recommendation as to avoided cost, but concluded modification was appropriate to develop a basis for avoided costs on a coal plant proxy of 200 MW rather than 400 MW. It then issued an order calculating avoided cost at 8.9 eents/kWh. Both PECO and Cambria filed appeals with this court from the PUC’s October 25, 1993 order directing PECO to enter into power purchase agreements with LG & E and American/CMS, and using a coal plant proxy to calculate avoided cost.

II.

PURPA was originally enacted in 1978 to combat the energy crisis of the early 1970’s resulting from increased oil prices and natural gas shortages. FERC v. Mississippi, 456 U.S. 742, 102 S.Ct. 2126, 72 L.Ed.2d 532 (1982). Under Section 210 of PURPA, 16 U.S.C. § 824a-3, the Federal Energy Regulatory Commission (FERC) was directed to promulgate rules to encourage the development of alternative sources of power, including rules requiring utilities to offer to buy electrical power from QFs. Under 16 U.S.C. § 824a-3(b), PURPA required that FERC promulgate rules to provide for purchase rates of power that did not discriminate against QFs. Congress also provided that those rates had to be just and reasonable to electric consumers of the electric utility and in the public interest; consequently, they had to provide a rate which did not exceed the avoided cost to the utility of purchasing power from a QF rather than building its own facility.

FERC enacted such regulations and required each state to implement PURPA. See 18 C.F.R. Part 292. Pursuant to that mandate, the PUC enacted regulations at 52 Pa.Code § 57.31 et seq. adopting rules regarding the purchase and sale of energy and capacity from QFs. Under 52 Pa.Code § 57.32(a), the PUC specifically delineated that electric utility consumers were to be protected, as well as equalizing the bargaining power between QFs and utilities. The intention was to ensure that the purchasing utility and its customers were in the same or similar position to what they would have been if capacity and energy had not been purchased from a QF. See Allegheny Ludlum Corporation v. Pennsylvania Public Utility Commission, 149 Pa.Commonwealth Ct. 106, 612 A.2d 604 (1992). This was accomplished by ensuring that the utility’s avoided costs of purchasing capacity and energy from a QF rather than building and operating its own facility was equal to or less than utility produced power so that its rates to consumers did not increase as a result.

PECO argues that the PUC violated both the federal and state mandates that ratepayers are to be protected because it did not consider whether it was advantageous to the ratepayers to order it to enter into two power purchase agreements for 160 MW of power as evidenced by its lack of findings regarding the public interest. PECO specifically contends that based on the evidence it presented, if it is required to enter into one or more agreements for the purchase of power, the result will be severe and needless rate increases to its customers. It contends that the PUC was required to make specific findings as to why the QFs’ purchases are in the public interest, not just in the QFs’. PECO, however, ignores that PURPA has determined that it is in the public interest for utilities to purchase QF power when (1) a utility has a need to purchase capacity and energy, and (2) the cost of purchasing that energy, which would ultimately be passed through to ratepayers, is at or below its avoided costs. Here, whether it is in the public interest for PECO to purchase 160 MW of power will be answered by determining:

• Whether there is substantial evidence to support the PUC’s determination that PECO has a need to purchase 160 MW of capacity and energy so that it may sufficiently provide service to its customers during the latter part of the 1990’s; and
• Whether the PUC’s determination that PECO’s avoided cost would be calculated based on a coal plant proxy was reasonable in determining the lowest available cost that would be passed through to the ratepayers.

If PECO has the need to purchase additional power and the cost of power purchased is at or below the avoided cost, then the PUC’s order is in compliance with PURPA and the purchase is presumed to be in the public interest.

A

The PUC’s finding that PECO needs to purchase additional capacity has the greatest impact on the public interest because it has the most impact on rates. If PECO is required to purchase power, its costs are passed directly to the ratepayers. Unlike most transactions where reward follows risk, the PUC’s order directing PECO to purchase power passes to the ratepayers the risk of paying for power if it proves to be excess. While ratepayers assume the risk, they will not see any reward because they will continue to pay the same electric rate regardless of whether the utility or the QF produces the power. Under the best of circumstances, the customers will continue to pay what they would have paid if the QFs did not generate the power but the utility did. Ratepayers incur a risk for QF power that they do not incur if the utility produces the power. A utility and its shareholders are required to assume the cost if the capacity proves to be excess. See 66 Pa.C.S. § 1323(a) ; West Penn Power Company v. Pennsylvania Public Utility Commission, 150 Pa.Commonwealth Ct. 349, 615 A.2d 951 (1992); petition for allowance of appeal denied, 536 Pa. 631, 637 A.2d 291 (1993). Contrary to the Pennsylvania statute regarding excess capacity, if QF capacity is excess, the ratepayers, not the utility or the QF, are required to assume the burden of paying for capacity not needed leading to increased rates.

The issue of whether capacity is needed in this case centers around growth forecasts, loss of capacity or customers. Under PURPA, the three QF developers had the burden to establish that PECO needed additional capacity. At the hearing, the developers and the OCA argued that PECO required varying amounts of increased capacity from 1997 through 2000. Each had different reasons. Some argued that PECO’s capacity need should be based on the availability of capacity from its parent company, GPU, while others argued that PECO could not rely on GPU, and its need for capacity had to be determined independently. The following is a summation of the parties’ arguments as to PECO’s need for capacity:

Alleged

Party Capacity Needed Reasons

LG & E 80-100 MW Considered PECO’s need for capacity looking first at the overall GPU system; determined that GPU’s need for capacity exceeded its planned capacity deficiency. Then looked at PECO’s individual capacity needs, and relying on its 1991 ARP, believed PECO would fail to meet its capacity obligation every year from 1991 through 2001. Offered to sell PECO 80 MW of power, arguing that additional capacity would allow PECO, through GPU, to satisfy the objective of the 1991 ARP to meet the GPU capacity obligation to PJM in 1997 and 1998.

Ameri- 219 MW can/ CMS Looked at GPU system as a whole in determining PECO’s need for capacity; believed it had substantial amounts of uncommitted capacity that created the false impression that GPU had adequate capacity to meet

Alleged

Party Capacity Needed Reasons

its obligations. Based on those shortages, PECO would need 219 MW at a minimum by the year 2000, but would have a capacity deficiency of nearly 450 MW based on other factors such as underforecasting, the impact of the Clean Air Act amendments and uncommitted capacity assumptions. Noted that proposed GPU/Duquesne project which promised 500 MW of capacity to fulfill GPU’s system-wide need might not be successful. Offered to sell PECO 300 MW of power.

Cambria 260-300 MW Viewed PECO’s capacity need on a “stand alone” basis rather than as part of the GPU system. Relied on PECO’s 1991 ARP which it contended was underforecasted. Believed that utilizing a 1.9% average growth rate and a reserve margin of 16%, PECO would need about 250 MW of capacity by the winter of 1997-1998 and about 310 MW by the winter of 1998-1999. Also argued that additional capacity would be needed based on Clean Air Act and retiring Warren generating facility. Suggested that because it indicated it intended to add two 125 MW combined cycle plants by 2000, it could simply eliminate the 125 MW plant scheduled for 1999 and grow into the 200 MW it had offered to provide.

Alleged

Party Capacity Needed Reasons

OCA 100-150 MW Relied on PECO’s 1991 ARP. Noted that PECO had forecasted low, but that it historically had been a relatively slow-growing company compared to the electric utility industry generally. It stated that PECO’s load forecast was based on reasonable data. It also stated that PECO’s underforecasting in the láte 1980’s was not a situation unique to it but a nationwide phenomenon related to a period of unusually strong economic growth and declining energy prices. It, too, commented on uncertainties in the future which would impact on PECO’s capacity needs, specifically pointing out that one of PECO’s major industrial customers, Bethlehem’s Bar, Rod and Wire Division in Johns-town, was closing, and the resulting loss of load was not a consideration in the load forecast contained in the 1991 ARP.

Coalition 80-100 MW Agreed with LG & E’s position.

PECO responded by arguing that it had no need for additional capacity through the year 2000 because its need for capacity was determined as part of the resource planning process of its parent GPU. It stated that additional capacity needs would be obtained by calling on GPU resources to meet the additional 125 MW it needed for growth during that time frame. It concluded that it could rely on GPU despite the fact that its 1991 ARP showed GPU needed 57 MW in 1997 and 20 MW in 1998. It contended that looking at GPU’s overall need, these small amounts were de minimis and should not be used to calculate power needs for PECO. Additionally, it argued that its needs were less because Bethlehem’s Bar, Rod and Wire Division was closing, and its capacity needs would be reduced by 110 MW of capacity it had been utilizing.

The PUC determined that PECO required an additional 169 MW of capacity by the year 2000 after examining PECO’s relationship with its parent company, GPU, and reviewing PECO’s 1991 ARP. It first considered PECO’s intended reliance on GPU’s capacity during the 1990’s. Even though PECO stated that its need for QF capacity was determined as part of the resource planning process of GPU, and the 1991 ARP indicated that GPU only needed 57 MW in 1997 and 20 MW in 1998, the PUC found that not only did GPU have a need for capacity of which its own resources were uncommitted, but that GPU placed great reliance on short-term purchases of capacity from other utilities. Because of GPU’s utilization of short-term capacity, the PUC found that PECO could not meet its long-term obligations to have a firm source of capacity with such purchases.

On appeal, PECO contends that the PUC erred in finding that it had a need to purchase power while Cambria contends that the PUC erred because what it found PECO needed was not sufficient. However, relying on PECO’s 1991 ARP, the PUC made the following calculation for PECO’s capacity need over a ten-year period beginning in 1997, notably subtracting from its total resources the additional 125 MW facility that PECO had scheduled to build by the year 1999, but which it admitted it was not going to build:

PECO’s anticipated net peak resources in the summer of the year 2000 2994 MW

less its anticipated 125 MW combined cycle plant to be built in 1999 - 125 MW

Total anticipated net peak resources 2869 MW

Total anticipated net peak resources 2869 MW

less PECO’s capacity target in the year 2000 3038 MW

Total peak resources available to meet capacity target < 169 MW >

The PUC noted that this calculation was consistent with the

OCA’s projection of up to 150 MW of capacity need.

PECO continues to argue that it needs no capacity because GPU’s capacity is sufficient to provide all it needs. However, as set forth previously, the PUC determined that PECO had a need to purchase 169 MW of additional capacity based on the 1991 ARP that PECO submitted, and that report was within a reasonable proximity to the date the proceedings were initiated. As such, the PUC properly relied on the figures contained in the 1991 ARP to calculate PECO’s anticipated capacity needs by the year 2000. The PUC’s role and duty is to review the record evidence, to make the appropriate credibility determinations, and to assign the appropriate weight to be given to the evidence presented. Armco Advanced Materials Corporation v. Pennsylvania Public Utility Commission, 157 Pa.Commonwealth Ct. 150, 629 A.2d 221 (1993) (Burgettstown II). By virtue of filing the 1991 ARP, PECO essentially admitted that its net resources, independent of GPU’s, were not sufficient to meet its target capacity by the year 2000.

PECO also argues that the PUC’s calculation of its capacity need was in error because it failed to consider its “uncontradicted evidence that the closing of Bethlehem’s Bar, Rod and Wire Division in Johnstown, Pennsylvania, would result in a loss of sales equivalent to the energy associated with 100 MW of average on-peak load.” While we agree that the record reflects that the PUC did not address the alleged closing of the Johnstown plant in any of its decisions, there is no evidence in the record that the Johnstown plant actually closed. Because there is no record evidence, the PUC, in not considering the Bethlehem plant’s closing in its ultimate calculation of PECO’s capacity needs, is not in error.

Cambria, on the other hand, argues that the PUC’s finding of 150-170 MW of needed capacity was too low because that figure was underestimated due to PECO’s underestimated growth forecasts in its 1991 ARP. In support of this contention, it points to the evidence presented by LG & E which indicated that PECO would have a capacity deficiency every year from 1991 through 2000. However, in determining that 160 MW of capacity was sufficient, the PUC apparently relied on the reasoning of the OCA which found that PECO had historically provided low growth forecasts and this was not unusual. Further, although Cambria relies on the evidence presented by LG & E, that evidence was only presented to support a finding that PECO had a need for 80 MW of capacity, not 200.

Cambria also argues that the PUC’s finding of only 150-170 MW violated PURPA because it only determined the minimum amount of capacity that PECO would need, and PURPA mandates the increase of conservation of electric energy and efficiency through the use of QFs. However, while the PUC stated that the filings and evidence in the proceeding indicated that 150-170 MW was minimally required by PECO to meet its capacity needs by the year 2000, it also specified that it was not convinced PECO would have a need for more than 150-170 MW of additional capacity by the year 2000. As such, its finding was in accord with PURPA because it determined the amount of capacity it believed PECO needed to satisfy its obligations by the year 2000.

As to Cambria’s argument that there was a need for additional capacity beyond 150-170 MW due to the impact of the Clean Air Act amendments and the closing of the Warren generating station by the year 2000 and its loss of 88 MW of capacity, the PUC acknowledged that the Clean Air Act amendments “will likely have an impact on any utility with substantial coal-fired facilities”, but it could not speculate on the retirement of such facilities. Regarding the Warren facility, the PUC stated that it was not clear whether this plant would actually be closing and directed PECO to inform it as to its plans to retire that facility. However, because there was no evidence that the Warren facility would actually be retiring from operation, the PUC properly did not include its 88 MW of capacity into its calculation of PECO’s need for capacity by the year 2000.

As to whether the PUC underestimated the amount of capacity PECO needed, the PUC stated, “while there is evidence supporting the proposition that GPU and Penelec may have underestimated capacity needs, we are not convinced that Penelec will in fact have a need for more than 150-170 MW of additional capacity by the year 2000.... The filings and evidence in this proceeding indicate that 150-170 MW is minimally required by Penelec to meet its capacity needs by the year 2000 as reasonably estimated from the vantage of the Spring of 1991.” (PUC opinion dated November 17, 1992, at pp. 35-36.) Because administrative decisions made by an agency in its area of expertise should be given deference, Norfolk and Western Railway Company v. Pennsylvania Public Utility Commission, 489 Pa. 109, 413 A.2d 1037 (1980), and there is substantial evidence supporting its determination that PECO needs 169 MW of additional capacity by the year 2000, the PUC did not err in ordering PECO to enter into purchase agreements for 160 MW of additional capacity.

B.

The second part of the test to determine if the purchase of power by PECO was in the ratepayers’ best interest requires us to determine whether that purchase was going to be made at or below PECO’s avoided cost that ultimately would be passed through to the ratepayers. PURPA has determined that rates for thé purchase of capacity and energy are not to exceed the avoided cost to the utility of alternative electric energy purchased from a QF. See 16 U.S.C. § 824a-3(b). Avoided cost is defined as the incremental cost to an electric utility of electric energy or capacity or both, which, but for the purchase from the QF, the utility would generate itself or purchase from another source. See 18 C.F.R. § 292.101(b)(6). In other words, it is what the utility’s costs would be if the utility produced the power.

Unlike the ALJ who made his calculation of 100 MW based on actual avoided costs, the PUC, in making its calculation, relied on 52 Pa.Code § 57.34(c)(4)(iii). That regulation requires that the estimated costs of a new coal plant which produces baseload power, rather than any other type of plant, be used to determine avoided costs. Referred to as a coal plant proxy, this calculation is only utilized when a utility requires additional capacity but is not committed to a QF or to building its own plant, and resultantly anticipates inadequate system reliability over the next ten years. The PUC issued this regulation because a coal-fired plant rather than any other type of plant is generally the least expensive way to generate baseload power. The PUC relied on the coal plant proxy to determine avoided cost without making any additional calculation, and determined that the lowest avoided cost would be calculated based on a hypothetical 200 MW coal plant proxy.

PECO and the OCA argue, however, that while a coal proxy may be appropriate to determine avoided cost when baseload power is needed, PECO’s 1991 ARP on which the PUC relied to figure capacity, indicates PECO needed intermediate power by the year 2000, not baseload. The next plant PECO intended to build within the requisite time-frame was a gas-fired combined cycle plant that would produce intermediate power, and the calculation of avoided cost based on that plant was less than using the coal proxy for baseload power. As such, they argue that the PUC’s use of a coal plant proxy resulted in a cost that exceeded PECO’s avoided cost and will require ratepayers to pay more for the power from the QFs than if PECO had pursued its own resource plan and generated the power itself.

Specifically, they point out that the use of the combined cycle intermediate power plant in calculating avoided cost resulted in a payment to the QFs of 8.467 cents/kWh for projects in-service as of 1997, while the use of a coal plant proxy was 8.9 cents/kWh. They argue that avoided cost should have been calculated based on a gas-fired combined cycle plant rather than a coal plant. Further, PECO contended that over the life of the plants, the 4.33 difference results in ratepayers paying approximately $692.80 or $4,855,142 each year of the 30-year contract that the plant is in operation.

To understand fully the OCA’s and PECO’s contentions, it is necessary to explain the difference between base, intermediate and peak power. The cost of building and operating a power plant is based on many factors. Two factors relevant to this case for purposes of discussing avoided cost are the quantity of capacity needed and the duration of time that capacity is used, both daily and seasonally. The quantity of capacity needed is determined by user demand or the rate at which the energy is delivered. Utilities categorize plants based on the cost of demand as follows: a) baseload power — the minimum demand and the least expensive to operate; b) intermediate power — more demand and more expensive to operate than baseload; and c) peaking power— the highest demand and the most expensive to operate. See West Penn Power, 150 Pa.Commonwealth Ct. at 376, 615 A.2d at 965.

Utilities operate baseload plants for long intervals because that is the amount of demand that is needed to be met at all times, while intermediate power is only used to meet demands that vary throughout the day. Peaking power is provided only a few hours per day during the times of highest demand. See James H. Cawley et al, Pennsylvania Public Utility Commission Rate Case Handbook, pp. 13-14 (1983). Regarding time of usage of power, there are off-peak times or low system demand periods and on-peak times when there are high system demands. Because the level of demand needed and the time and duration of usage may vary, it is not always prudent to calculate avoided cost based strictly on a baseload plant.

Assuming, arguendo, that PECO and the OCA are correct in their calculations and the use of intermediate power is cheaper than baseload in determining its avoided cost, the question then becomes whether the PUC can issue and rely on a regulation requiring the use of a coal plant proxy where the only evidence of record shows that it results in higher costs to consumers rather than doing an independent calculation to determine PECO’s true avoided cost. In other words, is the coal plant proxy regulation valid when used to set avoided cost for intermediate, or, for that matter, peak power.

The PUC argues that its regulation is valid and we should give it deference that the coal proxy will always provide the appropriate or lowest avoided cost, relying on our Supreme Court’s holding in Pennsylvania Human Relations Commission v. Uniontown Area School District, 455 Pa. 52, 313 A.2d 156 (1973). In Uniontown, our Supreme Court addressed the validity of an agency’s regulations that were attempting to correct defacto segregation. It found that statutory language giving the agency power to adopt regulations to effectuate the policies of the statute and correct such segregation meant that the standard necessary for appellate interference was extraordinarily high, far beyond simply considering the wisdom of the agency action, and that the standards set forth in American Telephone & Telegraph Company v. United States, 299 U.S. 232, 57 S.Ct. 170, 81 L.Ed. 142 (1936), were applicable. In that case, the United States Supreme Court stated:

This court is not at liberty to substitute its own discretion for that of administrative officers who have kept within the bounds of their administrative powers. To show that these have been exceeded in the field of action here involved it is not enough that the prescribed system of accounts shall appear to be unwise or burdensome or inferior to another. Error or unwisdom is not equivalent to abuse. What has been ordered must appear to be so entirely at odds with fundamental principles of correct accounting ... as to be the expression of a whim rather than an exercise of judgment.

AT & T, 299 U.S. at 236-237, 57 S.Ct. at 172.

Similar to Uniontown and particularly appropriate because we are interpreting a federal statute rather than state statute, is the U.S. Supreme Court’s decision in Chevron v. Natural Resources Defense Council, 467 U.S. 837, 843-844, 104 S.Ct. 2778, 2781-2782, 81 L.Ed.2d 694 (1984). In that case, the United States Supreme Court adopted a “strong deference” standard and explained the analysis to be used to determine the propriety of the agency’s legal regulation as follows:'

When a court reviews an agency’s construction of the statute which it administers, it is confronted with two questions. First, always, is the question whether Congress has directly spoken to the precise question at issue. If the intent of Congress is clear, that is the end of the matter; for the court, as well as the agency, must give effect to the unambiguously expressed intent of Congress. If, however, the court determines Congress has not directly addressed the precise question at issue, the court does not simply impose its own construction on the statute, as would be necessary in the absence of an administrative interpretation. Rather, if the statute is silent or ambiguous with respect to the specific issue, the question for the court is whether the agency’s answer is based on a permissible construction of the statute.

Chevron, 467 U.S. at 842-843, 104 S.Ct. at 2781-2782.

The PUC argues that PURPA is not clear and creates a gap because it does not address how avoided costs are to be assessed when a utility does not anticipate adequate capacity to cover its needs. It explains that its regulation requiring the use of a coal proxy in such an instance fills that gap because it determines the lowest avoided cost when a utility does not anticipate adequate capacity within the next ten years and has no commitment to build a plant. Because PECO does not anticipate enough capacity via its own plant through the year 2000, the PUC then contends it properly relied on its own regulation to utilize a coal plant proxy to assess avoided costs no matter what type of power is to be purchased-baseload, intermediate or peak.

The PUC also argues that applying those standards to this case, its adoption of the coal plant proxy regulation and its application was not so “unwise or burdensome or inferior” as required under Uniontown so as to justify a reversal. Further, even if it did err in adopting and applying the coal proxy resulting in a higher avoided cost and rates, it argues that its decision does not warrant reversal because the action must result from “a whim rather than an exercise of judgment.” Because it has repeatedly used the coal plant proxy throughout the years as an avoided cost benchmark, it cannot be considered an expression of whim to use the coal plant proxy when there is no commitment, but “must be seen as sound exercise of judgment.”

Rather than filling a gap, PECO and the OCA argue that the coal proxy regulation is contrary to PURPA and its implementing regulations. While recognizing deference must be given to the PUC’s regulation, they contend that the PUC’s reliance on its regulation requiring the use of a coal plant proxy was at odds with PURPA’s mandate that ratepayers not pay more than they would have been required to pay if the utility btdlt its own facility because it did not provide the lowest avoided cost. They contend that as a result of the PUC’s actions, ratepayers "will be required to subsidize the QFs.

Our standard of review over an interpretation of a regulation is limited. We will not substitute our judgment for the agency or strike down its regulations unless a clear abuse of discretion is shown or it is apparent that the agency has exceeded its statutory powers. Paratransit Association of Delaware Valley, Inc. v. Yerusalim, 114 Pa.Commonwealth Ct. 279, 538 A.2d 651 (1988); Blumenschein v. Housing Authority of the City of Pittsburgh, 379 Pa. 566, 109 A.2d 331 (1954). To determine whether there is an abuse of discretion, it must be shown that an agency did not consider all the relevant factors in arriving at its interpretation of the regulation. Citizens to Preserve Overton Park v. Volpe, 401 U.S. 402, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971). Whether it has examined the relevant factors depends on whether the agency has looked to the policies and goals of the statute which it is charged to enforce or implement. Even if the agency considered all of the factors and its decision was within statutory bounds, it still can be deemed to have abused its discretion and can be reversed if there is a clear error of judgment making the interpretation unreasonable. See Citizens to Preserve Overton Park; Rizzo v. City of Philadelphia 136 Pa.Commonwealth Ct. 13, 582 A.2d 1128 (1990), petition for allowance of appeal denied, 527 Pa. 653, 593 A.2d 424, 428 (1991); Lily Penn Food Stores, Inc. v. Pennsylvania Milk Marketing Board, 80 Pa.Commonwealth Ct. 266, 472 A.2d 715 (1984); National Industrial Sand Association, 601 F.2d 689 (3rd Cir.1979).

One of the goals of PURPA is to ensure that the cost of purchasing power by the utility is just and reasonable to the consumer and in the public interest. 18 C.F.R. § 292.304(a). As stated by the Conference Committee in the Conference Report on the bill that became PURPA:

The conference recognizes that cogenerators and small power producers are different from electric utilities, not being guaranteed a rate of return on their activity generally or on their activities vis-a-vis the sale of power to the utility and whose risk in proceeding forward in the cogeneration or small power production enterprise is not guaranteed to be recoverable.
* * * * * *
The provisions of this section are not intended to require the ratepayers of a utility to subsidize cogenerators or small power producers.

H.R.Confer.Rep. No. 95-1750 pp. 97-8 (1978); reprinted in 1978 U.S.C.C.A.N. 7659, 7831-7832.

Commenting on this provision, Justice Papadakos stated in his concurring and dissenting opinion in Armco Advanced Materials Corporation v. Pennsylvania Public Utility Commission, 535 Pa. 108, 111, 634 A.2d 207, 209 (1993), “The Congressional intent of the avoided cost pricing scheme is to make the utilities’ ratepayers economically indifferent between utility power plant additions and utility purchases of QF power.” This is accomplished by calculating a rate of purchase which does not exceed the avoided cost to the utility of purchasing power rather than building its own facility, and inherently takes into consideration the type of power needed by the utility to satisfy its customers’ needs. By adopting a regulation using a coal fire proxy appropriate to a baseload plant, the PUC, in interpreting this regulation, failed to consider that when intermediate power is needed, avoided cost can be less than a baseload plant. Under PURPA, its result is manifestly unreasonable because ratepayers cannot be indifferent to a rate that would be more than if the utility produced the capacity itself and would require them to subsidize the QFs at approximately $692.80/kWh.

In this case, PECO’s 1991 ARP upon which the PUC determined capacity states that it anticipates needing 125 MW of intermediate power by 1999 and again in 2002. In enacting the coal plant proxy, the PUC believed that because coal was a plentiful source, it would produce the lowest avoided cost. While the coal plant proxy is appropriate to determine the lowest avoided cost when a utility has not committed to a QF or to building its own plant and it requires baseload power, all of the evidence of record establishes that the coal plant proxy does not produce the lowest avoided cost when intermediate or peak power is needed. What made the PUC’s application of its regulation erroneous is that it applied a baseload avoided cost to a requirement of intermediate or peak power.

The only reason that the PUC used the coal proxy was because PECO was not committed to building a 125 MW combined cycle plant, and it alleged it was going to rely on its parent, GPU, for that power. The PUC disagreed with PECO that it could rely on GPU for its intermediate power, with the resolution of that disagreement being that the PUC could then rely on the coal fire proxy which produced a higher avoided cost. However, illustrating that the coal proxy does not always result in the lowest avoided cost was that if PECO had committed to build the 125 MW combined cycle plant as the ALJ found, the actual cost to ratepayers would have been at the lower 8.467 cents/kWh rate. Under PURPA, rates have to be transparent, and the lowest avoided cost passed through to ratepayers has to be determined by calculating the lowest avoided cost of the type of power needed, be it intermediate or peak power.

Because Congress requires that the avoided cost be based on what the ratepayer would have to pay if the utility produced the power, the PUC’s regulation regarding a coal-fired plant proxy is invalid. As such, ignoring the undisputed evidence that intermediate power was the type of capacity needed, the PUC’s use of that proxy without making an actual calculation of avoided cost was an abuse of discretion because it is not in accordance with PURPA’s direction that ratepayers should not be charged more for power than if the utility produced it. Consequently, the PUC is directed to calculate PECO’s avoided cost based upon a size of plant or plants that would produce the lowest avoided cost for intermediate power.

III. Priority

The last issue deals with the way in which the PUC determines which QF developer will be awarded a contract with a utility when more than one QF petitions the PUC to order that utility to enter into a contract with it for the purchase of capacity and energy. Specific to this case, the question that must be answered is whether the PUC properly determined that the date a legally enforceable obligation was incurred (for purposes of determining the priority of the QFs to contract with PECO as well as avoided cost) was based on a multitude of factors, including the date the QF first filed its petition with the PUC rather than solely on the date the QF made a bona fide offer to the utility.

The PUC concluded that LG & E and American/CMS had priority over Cambria to enter into power purchase agreements with PECO, initially based on the following two preliminary requirements:

• the QF must demonstrate it is somewhat developed rather than merely being a concept; and
• the QF must have contacted the utility and attempted to reach an agreement.

It then stated that once these criteria were met, the determination of a priority assessment would be based on:

• experience of the proposed developers;
• viability of the proposed project;
• benefits of the proposed project;
• quality of existing utility service to the host site;
• project size; and
• time of initiation of PUC proceedings.

Addressing each of those factors, the PUC noted that all of the developers had substantial experience in developing such projects and there was no need to differentiate between them on that basis. Further, each project would provide certain economic benefits. However, on the question of the viability of the projects, the PUC commented that because Cambria did not identify a steam host even though it was proposing to build a cogeneration facility, it was a less viable project than the others.

Finally, the PUC addressed Cambria’s earlier stated concerns regarding LG & E being the first to file in this proceeding. The PUC stated:

Since we by no means wish to encourage litigation, we again specifically note that we will only reach such considerations as ‘first to file’ when the projects demonstrate compliance with our preliminary requirements. Because American/CMS was the second to file its pleadings in the instant proceeding, because it identified a steam host and because there is evidence of record indicating its negotiations with Penelec in an attempt to reach a purchase agreement, we accord second priority to American/CMS. (PUC order of November 17, 1992, at pp. 45-46.)

Cambria argues, however, that the PUC should have awarded it first priority to contract with PECO because priority should be based solely on the date the QF made a bona fide offer to the utility rather than the date it filed its petition with the PUC. Cambria contends that even though it was the last QF to file a petition with the PUC, it was the first to make PECO a bona fide offer on April 30, 1990.

Cambria directs our attention to PURPA regulations which mandate that a utility purchase capacity from a QF if it has such a need. 18 C.F.R. § 292.303(a) provides in pertinent part:

(a) Obligation to purchase from qualifying facilities. Each electric utility shall purchase, in accordance with § 292.304, any energy and capacity which is made available from a qualifying facility.

Section 292.304 provides that purchases are to be made pursuant to a “legally enforceable obligation.” Cambria then relies on this court’s holding in Armco Advanced Materials Corporation v. Pennsylvania Public Utility Commission (Milesburg II), 135 Pa. Commonwealth Ct. 15, 579 A.2d 1337 (1990), affirmed, 535 Pa. 108, 634 A.2d 207 (1993), where we determined what constituted a legally enforceable obligation. We held that:

Where a QF has done everything within its power to create such an obligation, either by tendering a contract to the utility or by petitioning the PUC to approve a contract or to compel a purchase, and only an act of acceptance by the utility or an act of approval by the PUC remains to establish the existence of a “contract”, then the “legally enforceable obligation” contemplated by § 292.304(d)(2) has been created, and the QF is entitled to rates based on avoided costs calculated from the date of the QF’s action.

Milesburg II, 135 Pa.Commonwealth Ct. at 33, 579 A.2d at 1347.

However, Cambria’s reliance on Milesburg II is misplaced. That case only dealt with the date that avoided costs should be calculated after the utility and a QF had agreed to enter into a power purchase agreement rather than, as here, where the QF is asking the PUC to impose the terms of an agreement. While we agree with Cambria that the date a QF makes a bona fide offer to the utility is an important factor when determining the priority of competing QFs, we part company when Cambria argues that it should be the sole determining factor.

We agree with the PUC that when there are competing QF projects and they are the same in virtually all respects, then it is fair to use the bona fide offer standard to determine priority because that is a distinguishing factor as to the QF’s ability and commitment to the project. However, if all of the projects are not the same and some are less viable than others, then the time a bona fide offer was made should not be the deciding factor because the QF has less potential of becoming a reality than the other projects and the offer does not change that. The PUC essentially arrived at this same conclusion by setting forth its preliminary and subsequent criteria to determine priority of QFS and determining that Cambria’s project was less viable because it had not identified a steam host.

We agree with the PUC’s decision to utilize the first to file rule as a determining factor because it would be pointless to require a utility to contract with a QF that did not actually have a viable project or was interested in building a facility which would produce far more power than was actually needed. Without the ability to provide the needed capacity and energy, the QF project would be defeating the purpose of PURPA — to require the utility to enter into a contract with the QF for the purchase of power when the QF has the ability to provide it with power and the utility has a specific need for . that power. We decline to agree with Cambria that the determining factor of priority is the date a QF makes a bona fide offer to the utility, regardless of whether the QF can provide what is needed, because in order to do so, we would be ignoring the mandate of PURPA, FERC and the PUC’s regulations.

Accordingly, for the foregoing reasons, the decisions of the PUC requiring PECO to enter into two power purchase agreements for 80 MW each with LG & E and American/CMS are affirmed, but the case is remanded so that the PUC can calculate PECO’s avoided cost in accordance with this decision.

ORDER

AND NOW, this 4th day of August, 1994, the order of the Pennsylvania Public Utility Commission dated October 25, 1993, is affirmed as it relates to the mandate that PECO enter into two agreements for the purchase of 160 MW of power. Its order is reversed as to its mandate that avoided cost be calculated based on a coal plant proxy. The case is remanded to the PUC to recalculate PECO’s avoided cost based upon a plant or plants of an appropriate size that would produce intermediate power in order to determine PECO’s lowest avoided cost that will be passed through to the ratepayers. Jurisdiction is relinquished. 
      
      . PECO is one of three operating companies owned by General Public Utilities Corporation (GPU). GPU’s other subsidiaries are Metropolitan Edison Company and Jersey Central Power & Light Company. GPU participates in the Pennsylvania — New Jersey — Maryland Interconnection (PJM), a formal and closely coordinated power pool consisting of electric utility members of the Mid-Atlantic Area Council.
     
      
      . Cambria Partners is a venture between Foster Wheeler Power Systems, Inc., C. Itoh & Co., Inc./Enprotech and WPEC, Inc.
     
      
      . Section 201 of the Public Utility Regulatory Policies Act of 1978 (PURPA), 16 U.S.C. § 796(18)(A), defines a qualifying cogeneration facility as one which produces electric energy and steam or forms of useful energy which are used for industrial and commercial heating or cooling purposes.
     
      
      . The original petition was filed by Bethlehem Steel Corporation, Bechtel Development Company and Bechtel Eastern Power Corporation (Beth/Bechtel) who offered PECO a contract to purchase capacity and energy from its proposed 80 MW bituminous coal waste-fired QF to be located at Mineral Point in Cambria County, Pennsylvania. Bechtel eventually transferred its rights in the project to Hadson Development (Beth/Hadson) and changed the location of its plant to the IP mill in Erie, Pennsylvania. Subsequently, Bethlehem Steel withdrew its petition because it only had an interest in the Mineral Point project, and Hadson was acquired by LG & E.
     
      
      . The 1991 ARP only indicated the amount of peak power needed during the summer and winter months of 1991 through 2010.
     
      
      . Pursuant to 52 Pa.Code § 57.34(c)(4)(iii), a coal plant proxy is used to provide the estimated construction costs of a new coal plant when a utility anticipates inadequate system reliability as a result of not being committed to a sufficient plant during any period over the next ten years.
     
      
      . See 18 C.F.R. § 292.302(b)(2) which requires a utility to file information indicating its plan for capacity additions and retirements for each year of the succeeding ten years; and 52 Pa.Code § 57.33(b)(1)(h) which requires that a utility indicate its plan for addition and retirements for all plants over a ten-year period and (iii) requires a full explanation of the costs of any kind of firm capacity the utility is planning to add.
     
      
      . In choosing to utilize a coal plant proxy as a basis for determining avoided costs, the PUC stated:
      The intent of § 57.34(c) is to have payments for qualifying facility capacity track the costs of capacity that a utility can avoid. Thus if a utility is committed to one or more types of additional generating capacity, and has spent a certain amount of money on such plant, it is only the amount of money remaining to be spent that would be considered as being “avoidable.” Of course, the entire cost of a capacity addition will be avoidable if the utility has spent nothing on that plant. If the utility has spent nothing on that plant, it may well be that the utility will have a capacity need within the next ten years. That is the case in this proceeding.... The Commission chose a coal plant as the proxy in recognition that over time a coal plant in Pennsylvania is likely to be a least-cost supply resource, considering the expected capital investment, reliability, and operating rate for producing electricity with coal as a fuel. This resource was chosen because it was the least expensive option, not because it provided high payments to qualifying facilities. (Emphasis in original.)
      (PUC order entered November 17, 1992, at pp. 36-37.)
     
      
      . Prior to the PUC issuing an order based on the recommended avoided cost calculation, PECO, LG & E and the Coalition of Concerned Citizens from Erie (Coalition) filed a joint petition for settlement with the PUC dated May 5, 1993, stating those parties had agreed to enter into a power purchase agreement for an 80 MW facility, and that the PUC should eliminate all support for use of a coal plant proxy as the pricing benchmark for that project or any of the other projects at issue. The parties then requested the PUC to approve the terms of the settlement without modification, direct PECO to enter into a power purchase agreement with LG & E pursuant to the terms of the settlement and as the sole and exclusive contract resulting from this proceeding, and terminate this proceeding. Both Cambria and American/CMS filed responses objecting to the joint petition for settlement because they were not parties to that settlement. American/CMS specifically noted that the settlement agreement would extinguish its express right granted by the PUC to enter into a contract for the sale of energy and capacity to PECO in the amount of 80 MW. The PUC denied the relief requested except to the extent that PECO and LG & E were to proceed with a power purchase agreement, noting that PECO and LG & E were not the only parties to the proceeding and it would not reconsider its prior orders.
     
      
      . PECO also filed a petition for stay or supersedeas with the PUC on November 9, 1993, requesting that its order entered on this matter dated October 25, 1993, be stayed. That petition was denied by the PUC by order entered January 13, 1994.
     
      
      . That section provides in pertinent part:
      Excess capacity costs. Whenever a public utility claims the costs of an electric generating unit in its rates for the first time and the commission finds that the unit results in the utility having excess capacity, the commission shall disallow from the utility’s rates, in the same proportion as found to be excess capacity:
      (1) the return on specific unit or units of any excess generating reserve;
      (2) the return on the average net original cost per megawatt of the utility’s generating capacity; or
      (3) the equity investment in the new unit.
      In addition to the disallowances set forth in this subsection, the commission may disallow any other costs of the unit or units which the commission deems appropriate. For the purposes of this section, a rebuttable presumption is created that a unit or units or portion thereof shall be determined to be excess unless found to be needed to meet the utility’s customer demand plus a reasonable reserve margin in the test year or the year following the test year, or, if it is a base load unit, it is also found to produce annual economic benefits which will exceed the total annual cost of the plant during the test year or within a reasonable period following the test year.
     
      
      . LG & E provided the following 1991 projections of PECO’s capacity deficit:
      Year MW
      1996 <65>
      1997 <82>
      1998 <119>
      1999 <146>
     
      
      . American/CMS noted that in order for GPU to maintain reliability of the PJM power pool, it had to meet a capacity obligation .to PJM. Because the current PJM target for maintaining reliability was a 22% reserve margin above its projected summer peak, American/CMS argued that in order to reach a 20% reserve margin, PECO would need 219 MW of capacity by the year 2000.
     
      
      . American/CMS stated, “By the year 2000, Penelec will have a capacity deficiency of nearly 450 MW. This reflects the stated deficiency of 169 MW, the acknowledged expiration of the aging 88 MW Warren Station, and the need of approximately 192 MW to compensate for the unreasonably low growth forecast.”
     
      
      . Utilizing a reserve margin of 18%, Cambria argued that PECO’s capacity need would be approximately 300 MW by the winter of 1997-1998, and 365 MW by the winter of 1998-1999.
     
      
      . It also stated:
      Penelec [PECO] and its two sister operating companies, Metropolitan Edison Company and Jersey Central Power & Light, have been national and state leaders in the procurement of non-utility generation resources.... The GPU operating companies have developed nearly 40 major power purchase agreements and commitments with non-utility generation developers for nearly 2300 MW of generating capacity. Penelec has agreements for almost 400 MW of such capacity, of which almost 200 MW are in operation and more than 100 MW are under construction.
      PECO further added that its capacity should be examined on a system-wide basis because the GPU companies have an agreement that if a GPU company needs capacity, it must purchase energy from any GPU company that has a temporary surplus, as long as capacity is not needed at the GPU system level.
     
      
      . Because Section 210 of PURPA, 16 U.S.C. § 824a-3, mandates that a utility enter into a long-term agreement with a QF developer if it requires additional power, and the PUC is not permitted to refuse such a requirement, the PUC inherently has the authority to determine if a utility actually needs additional capacity once a QF has filed a petition with the PUC alleging that the utility has failed to enter into a power purchase agreement for the sale of capacity and energy.
     
      
      . The PUC noted that even though PECO contended that it did not anticipate inadequate system reliability because it could rely on GPU, its regulations at 52 Pa.Code § 57.33(b)9(l)(ii) required a utility to be committed to sufficient plant, and that referred to the commonly accepted view that a utility have a large enough generating reserve margin to meet its obligation. It continued to state that the regulations did not contain a specific reserve margin because different reserve margins were appropriate for different utilities, but PJM member companies had reserve margin requirements of 22-23% which appeared to be a reasonable range for determination of utility capacity needs vis-avis QF offers to sell capacity.
     
      
      . The PUC also noted that GPU placed reliance on a purchase of capacity from Duquesne Light Company, “although the capacity value of that purchase would be reduced dramatically in the plausible event that the proposed GPU-DQE 5000 kv transmission line is not completed by 1996. The exhibit also demonstrates the JCP & L (Jersey Central Power & Light, a sister company of PECO), which imposes the lion’s share of capacity need upon the GPU system, will be relying on a huge amount of qualifying facility capacity (approximately 1200 MW), far more than the amount of qualifying facilities anticipated to be added by Penelec and Met Ed." The PUC then determined that PECO was relying on meeting its capacity requirements in part by relying on these procurements, but presciently noted that they could fail to come ■ through.
     
      
      . The PUC also noted that PECO anticipated very low winter reserve margins, which if viewed independent of GPU, would require drastic actions to correct.
     
      
      . This court’s scope of review from final orders of the PUC is limited to determining whether constitutional rights have been violated, an error of law committed or whether the PUC’s findings and conclusions are supported by substantial evidence. West Penn Power Company v. Pennsylvania Public Utility Commission, 134 Pa.Commonwealth Ct. 53, 578 A.2d 75 (1990); petition for allowance of appeal denied, 527 Pa. 660, 593 A.2d 429 (1991).
     
      
      . Although PECO now argues that the 1991 ARP should not be the basis for any decision by the PUC because it was filed two months after the petitions were filed by the three QF developers, nothing in the PUC Regulations, PURPA or FERC dictate the type of evidence upon which the PUC must rely in determining a utility’s capacity requirements. Here, the ALT and the PUC properly decided that the 1991 ARP was a valid source to determine PECO’s capacity needs because it had the most reasonable proximity to the date the proceedings were initiated. Also, the 1991 ARP was an annual public filing made by PECO as required by federal regulation (18 C.F.R. § 292.302(b)(2)), as well as state regulation (52 Pa.Code § 57.33(b)(l)(ii)), in which it identified its anticipated future needs. Moreover, it was a document of record in this case. As such, the PUC did not err by relying on that document in determining PECO’s future capacity needs.
     
      
      . The figures in the 1991 ARP on which the PUC relied were all figures relating to peak load power. Peak load power refers to the time of day or year when there is the highest point of demand by customers. In terms of costs, providing peak load power is most expensive, while baseload power is least expensive.
     
      
      . The 1991 ARP also provides that there would be a reserve margin of 566 MW for the summer of 2000, approximately 20% of the net resources available. The PUC indicates that the average margin percentage acceptable is approximately 22%.
     
      
      . Under 52 Pa.Code § 57.34(c)(4)(i), a utility will be considered to be committed to a plant if any of the following criteria are met:
      (A) The utility has spent 10% or more of the total estimated cost of construction or implementation.
      (B) The plant is due on line within 8 years, if a base load plant, or 5 years, if not a base load plant.
      (C) Contracts have been signed for significant components of the plant.
     
      
      . It was anticipated by the PUC that coal would be the least-cost supply resource over time. In its November 17, 1992 decision, the PUC explained, "the Commission chose a coal plant as the proxy in recognition that over time a coal plant in Pennsylvania is likely to be a least-cost supply resource, considering the expected capital investment, reliability, and operating rate for producing electricity with coal as a fuel. This resource was chosen because it was the least expensive option, not because it provided high payments to qualifying facilities.” (PUC opinion dated November 17, 1992, at p. 37.) (Italics added.)
     
      
      . In arriving at the 200 MW figure, the PUC apparently relied on PECO’s 1991 ARP, in which it provided its future generating capability installations, changes and removals for a 20-year period beginning in 1991 and ending in 2010. That document, which provided information regarding the installations of additional facilities to provide added capacity and energy, indicated that PECO intended to build two coal plants by the year 2010, each providing 200 MW of capacity:
      Net Capability (MW)
      Station Fuel Type Summer Winter Effective Date
      Combined Cycle NG 125 147 1/1/99
      Combined Cycle NG 125 147 1/1/02
      Coal 1 BIT 200 200 5/05
      Coal 2 BIT 200 200 5/10
      Explaining its decision, the PUC stated, PECO "considered various supply options of 200 MW capacity as a way of meeting its capacity needs through the end of the decade. Thus it is certainly reasonable to use 200 MW as a benchmark for a coal plant proxy.”
     
      
      . PECO also argues that the PUC erred by utilizing the coal plant proxy because it had no intention of building a coal plant until 2005. Specifically, it contends that a coal proxy should not have been used because a proxy is only used when a utility anticipates inadequate system reliability, and it anticipated adequate system reliability for a ten-year period because it was tapped into GPU's resources. However, as we have already indicated, GPU has a need for capacity of which its own resources are uncommitted. Therefore, PECO cannot rely on GPU's resources for purposes of its own system reliability.
     
      
      . As the 1991 ARP indicates, two combined cycle plants are anticipated to be built by the year 2002. The first coal-fueled plant which is anticipated to provide 200 MW of power is not expected to be in service until the year 2005, beyond the ten-year parameter of the PUC's decision. Because the PUC’s decision is, by its own designation under 52 Pa.Code § 57.33(b)(l)(ii), limited to determining PECO’s needs for a ten-year period beginning in 1991, and neither coal plant is going to be in service until after 2001, the PUC’s reliance on that figure to determine a coal plant proxy was improper.
     
      
      . In Chevron, the United States Supreme Court stated:
      The power of an administrative agency to administer a congressionally created program necessarily requires the formulation of policy and the making of rules to fill any gap left, implicitly or explicitly, by Congress. (Citations omitted.) If Congress has explicitly left a gap for the agency to fill, there is an express delegation of authority to the agency to elucidate a specific provision of the statute by regulation. Such legislative regulations are given controlling weight unless they are arbitrary, capricious, or manifestly contrary to the statute. Sometimes the legislative delegation to an agency on a particular question is implicit rather than explicit. In such a case, a court may not substitute its own construction of a statutory provision for a reasonable interpretation made by the administrator of an agency.
     
      
      . PECO does not anticipate needing 200 MW of baseload power until 2005 and not again until 2010, outside the ten-year range.
     
      
      . The PUC stated that evidence of that development included design and engineering studies, site location, détermination of fuel type, determination of operating size range, and a steam host if the project is a cogeneration facility.
     
      
      . Cambria argues that the PUC’s determination of the legal criteria to be applied in determining priority violated its right to a fair hearing. However, the PUC's criteria were merely the considerations or the rationale as to how they arrived at their decision to prioritize the QFs. Using the criteria was a matter of judgment within the agency's decision-making process. As the PUC notes, its September 1991 order setting out the "criteria” was not meant to provide a definitive standard for judging the relative merits of QFs or their priority for entitlement to a contract, but only recited considerations that led it to preliminarily conclude that LG & E was entitled to a contract. While Cambria would ask us to require the PUC to have a second hearing every time it adopts a rationale for its decisions, such a decision would undermine the authority of an agency to make decisions, as well as hold up the decision-making process.
     
      
      . The PUC did not specify in its opinion that the developers had met the two preliminary criteria. However, based on the record, it is clear that all of the developers attempted to negotiate a deal with PECO, and that they had demonstrated they were somewhat developed rather than merely being a concept, with the one exception of Cambria not identifying a steam host for its project.
     
      
      . Regarding the quality of existing utility service to the host site, the PUC stated, "There has been substantial testimony in this proceeding concerning inadequacies in the Penelec system at the International Paper plant in Erie. We will not give this evidence great weight, although it lends additional support to our determination that LG & E be given priority.” As to the size of the plants and the initiation of proceedings, it also noted that both Cambria and American/CMS offered to reduce the size of their projects, but LG & E was the first developer to propose a project sized at 80 MW, and it was first to initiate proceedings with the PUC.
      Cambria argues, though, that the PUC erroneously arrived at this conclusion because it was not permitted to admit additional evidence at the hearing on this subject. Cambria, which filed a petition for rehearing after LG & E acquired Beth/Hadson, contends that it could not submit any direct evidence while that petition was pending. However, the PUC stated in its decision, “There was no reason for any party to presume that the Commission would have decided the petition for rehearing, or decide it in any particular way, thus there was no reason to refrain from presenting testimony until a request for rehearing or reconsideration was decided.” We agree with the PUC that simply because a petition for rehearing was pending was no reason not to present its case on direct when it had every opportunity to do so.
     
      
      . The following are the dates of offers made by the QFs to PECO and their filings with the PUC:
      OF Date of Offer to PECO Date of Filing with PUC
      Beth/Bechtel 11/06/86 07/08/87
      Beth/Hadson 11/07/90 03/21/91
      LG & E *** 12/23/91
      American/CMS 11/30/90 04/05/91
      Cambria 04/30/90 . 04/27/91
      *** LG & E did not make a specific offer to PECO for the purchase of power, but relied on the date that Beth/Hadson had made its offer to PECO in November of 1990.
     
      
      . Interestingly, PECO argues that none of the projects were viable because they were not capable of delivering energy, and the PUC should not have awarded any contract based on that factor. However, not only did the PUC find that both the LG & E and American/CMS projects were viable, but PECO ignores its filing with the PUC for approval of a settlement agreement between it and LG & E for the purchase of power. If such a project was not viable, PECO would not have made such a request. As such, PECO's argument is meritless.