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State of Florida
Public Service
Commission
Capital Circle Office Center 2540 Shumard
Oak Boulevard
Tallahassee, Florida 32399-0850
-M-E-M-O-R-A-N-D-U-M-
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DATE: |
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TO: |
Director, Division of the Commission Clerk & Administrative Services (Bayó) |
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FROM: |
Division of Economic Regulation (Harlow, McRoy) Office of the General Counsel (Vining, Halloran) |
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RE: |
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AGENDA: |
06/21/05 – Regular Agenda – Posthearing Decision – Participation is Limited to Commissioners and Staff |
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COMMISSIONERS ASSIGNED: |
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PREHEARING OFFICER: |
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SPECIAL INSTRUCTIONS: |
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FILE NAME AND LOCATION: |
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Progress Energy Florida, Inc. (PEF) currently purchases 414 megawatts (MW) of capacity and the associated energy from the Southern Company (Southern) under two unit power sales (UPS) agreements. These agreements were executed in 1988, and are set to expire on May 31, 2010. The existing UPS agreements consist of coal-fired generation from Southern’s Plant Scherer in Georgia, and Plant Miller in Alabama.
As a part of its annual fuel adjustment filing in Docket No. 040001-EI, PEF requested Commission approval for cost recovery of the anticipated extension of the existing UPS agreements with Southern. At the time, PEF had not yet finalized the agreements with Southern, so PEF filed a Letter of Intent it had entered into with Southern to extend the existing 1988 UPS agreements. At the prehearing conference for Docket No. 040001-EI, held on October 25, 2004, the Prehearing Officer ruled that the Commission would not address the issue until an agreement was finalized and filed with the Commission.
On November 24, 2004, PEF signed two new UPS agreements with Southern, which will replace the existing agreements upon expiration. The two new UPS agreements consist of 424 MW of capacity, including 74 MW of coal-fired capacity from Plant Scherer in Georgia. The remaining 350 MW of capacity will be provided by Southern’s natural gas-fired combined cycle unit, Franklin 1, located in Alabama. The term for each agreement is June 1, 2010, through December 31, 2015.
On December 13, 2005, PEF filed a petition requesting a finding from the Commission that entering into the UPS agreements is a reasonable and prudent action by PEF to maintain its 20 percent reserve margin. PEF also requested recovery of the energy and capacity costs associated with the agreements, subject to Commission review of the actual expenses in the annual Capacity and Fuel Cost Recovery Clause proceedings. On March 14, 2005, the Commission issued Order No. PSC-05-0272-PAA-EI, approving PEF’s petition.
On March 31, 2005, White Springs Agricultural Chemicals, Inc. (White Springs) filed a Petition for Hearing and Motion to Intervene. The matter was set for hearing on June 2 and 3, 2005, by Order No. PSC-05-0432-PCO-EI, issued April 20, 2005. A hearing was held on June 2, 2005. Post-hearing briefs were filed by the parties on June 8, 2005.
The Commission has jurisdiction over this subject matter pursuant to Sections 366.04, 366.05, and 366.06, Florida Statutes.
Issue 1:
Did PEF adequately consider alternatives to the proposed UPS agreements?
Recommendation:
Yes. PEF did not issue a Request for Proposals (RFP). However, this is not required by Rule 25-22.082, Florida Administrative Code, and PEF adequately tested the market for alternatives through other means. PEF reviewed coal options, but determined that its 2010 need cannot be met by new or existing coal generation. PEF tested the pricing of the gas-fired Franklin capacity by comparing the pricing to gas-fired bids in PEF’s recent RFPs. The pricing appears to be comparable. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF’s marketers constantly look for appropriate purchases. PEF analyzed coal options, but they cannot meet 2010 needs. Recent RFPs produced no coal proposals and the Franklin agreement compares favorably to recent RFP responses. Nothing suggests additional analysis would be fruitful. Requiring an RFP would put this opportunity at risk.
W. SPRGS:
No. The evidence demonstrates that PEF failed to reasonably consider alternatives to the UPS agreements. PEF did not engage in an RFP or other process to identify supply alternatives and failed to demonstrate that it engaged in prudent utility planning to assure the proper mix of lowest cost resources.
Staff Analysis:
PEF did not issue an RFP to compare options to the proposed UPS agreements. (TR 128, 156) However, Rule 25-22.082, Florida Administrative Code, the “bid rule,” does not require investor-owned utilities to issue RFPs for the extension of power purchases. Witness Waters admitted that an RFP would provide greater assurance that the lowest cost option had been selected. (TR 158) Witness Waters also stated, however, that if PEF delayed the agreements to issue an RFP, the agreements, and in particular the coal-fired capacity, could be placed at risk. Southern has no obligation to bid into an RFP, or to wait until after PEF completed an RFP process before selling the capacity to another party. (TR 263-264) Witness Waters believes that other parties that are deciding whether to build would be looking for capacity in the 2010 time-frame. (TR 156-159, 233-234) Staff believes that while an RFP would have given more assurance that lower cost options were not available, it was reasonable for PEF to not issue an RFP in this instance. Staff agrees with PEF that delaying the contracts to issue an RFP could have placed the agreements, particularly the coal capacity, at risk. The recent high and volatile natural gas prices have increased the value of coal capacity for utilities; therefore, it is reasonable to assume that Southern could have sold the 74 MW of coal capacity to another party, even a relatively small municipal or cooperative utility. Staff notes that municipal and cooperative utilities have no obligation to issue an RFP or request cost recovery from the Commission. (TR 163)
Staff disagrees with White Springs’ position that PEF “failed to reasonably consider alternatives to the UPS agreements.” Witness Waters testified that he is “unaware of any merchant coal generation in Florida, other than one facility we are currently in negotiations with for purchases beginning in 2006.” (TR 34) PEF has received no coal-fired bids from existing units in response to its two most recent RFPs. (TR 34, 127) Witness Waters stated that he knows of several utilities that are planning coal-fired generating units in Florida and the surrounding states; however, these units will not be placed in service prior to the 2010 need. (TR 262) PEF compared the proposed natural gas-fired Franklin agreement to the bids in its most recent RFPs and found the pricing to be comparable. (TR 19, 263)
In conclusion, staff believes that while PEF did not issue an RFP, PEF adequately tested the market for alternatives through other means. PEF reviewed coal options, but found that new coal generation cannot be placed in service in time to meet the 2010 need. PEF has received no bids from existing coal generation in response to its two most recent RFPs. This provides some level of assurance that the proposed UPS agreements could not be replaced by lower priced existing coal generation. PEF is also in negotiations for a coal capacity contract beginning in 2006. As a test for the pricing of the gas portion of the proposed agreements, PEF compared the proposed natural gas-fired Franklin agreement to gas-fired bids in its two most recent RFPs. The pricing appears to be comparable.
Issue 2:
Is PEF's cost-effectiveness analysis reasonable and supported by the evidence?
Recommendation:
Yes. PEF used an accepted planning methodology to develop the expansion plans compared in its analysis, and its base-case mirrors its approved 2004 Ten-Year Site Plan. PEF’s flawed initial analysis casts doubt on the specific short-term savings. However, significant savings will occur during the contract term because the contracts should defer combined cycle capacity. Given the more certain up-front benefits and additional non-price benefits, the agreements are worth the risk that an expansion plan that includes the agreements may have a negative $5 to $11 million net present value through 2055. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF’s economic analyses utilized the same industry standard models and assumptions typically used for developing Ten Year Site Plans. The evidence demonstrates that the base plan used in PEF’s analyses appropriately represents the most cost effective plan that PEF would pursue absent the purchases under the UPS Agreements.
W. SPRGS:
No. PEF failed to demonstrate that its “base case” and “altered case” can reasonably be expected to produce the least cost or best alternative. PEF has only demonstrated that the altered case may produce short-term benefits when compared solely to its base case.
Staff Analysis:
PEF tested the cost-effectiveness of the proposed UPS agreements by comparing two expansion plans, a “base case” without the agreements, and a second case which included the agreements. (TR 35, EXH 2) The generating units included in each expansion plan are reflected below:
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Base Case Expansion Plan (without UPS agreements) |
Alternative Expansion Plan (with UPS agreements) |
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2010 combined cycle |
2011 combined cycle |
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2012 combined cycle |
2018 combined cycle |
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2017 coal |
2015 coal |
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2019 combustion turbine |
2017 combustion turbine |
Staff disagrees with White Springs that PEF did not demonstrate that its base case was least cost. PEF appears to have used accepted planning methodology to develop its base case expansion plan, and the resulting plan closely mirrors the expansion plan in PEF’s 2004 Ten-Year Site Plan. (TR 35, 130; EXH 2) The Commission reviewed PEF’s 2004 Ten-Year Site Plan and found the Plan to be suitable for planning purposes.
As can be seen in the table, according to PEF’s analysis the UPS agreements defer the need for one natural gas-fired combined cycle unit from 2010 to 2011, and defer a second combined cycle from 2012 to 2018. In PEF’s analysis, the in-service date of a coal unit is also advanced from 2017 to 2015, due to the addition of the UPS agreements. PEF provided two cost comparisons of the expansion plans: 1) a short-term analysis over the five-year contract term; and, 2) a long-term analysis from 2010 to 2055, representing the five-year term of the contract, followed by the assumed 40-year life of a 2015 coal-fired generating unit.
PEF’s initial short-term net present value (NPV) analysis showed a significant up-front savings of $133 million from 2010 until 2015, due to the deferral of the two combined cycle generating units. PEF also estimated an additional $12 million in potential savings from economy purchases facilitated by the transmission associated with the agreements. PEF’s assumptions used in estimating these cost savings from economy purchases appear to be reasonable. PEF’s long-term comparison of the two expansion plans resulted in a negative $5 million NPV over 45 years, with a base case economy energy purchase assumption. PEF performed a sensitivity analysis assuming a 50 percent economy purchase reduction, which resulted in a negative $11 million NPV over 45 years. (TR 34-38)
On May 10, 2005, Witness Waters filed supplemental testimony in which PEF revised its estimated five-year contract term benefits downward from $133 million to $44 million. (TR 46) Witness Waters stated that the error involved the values used for the capital expenses for the proposed units in PEF’s year-by-year analysis. PEF was unable to provide copies of the back-up spreadsheets or to recreate its flawed analysis. (TR 63, EXH 2) Staff finds it troubling that PEF cannot identify where or how the error occurred. However, Witness Brubaker’s attempt to recreate PEF’s short-term analysis resulted in a $37 million NPV savings. Witness Brubaker stated that the difference between the $44 million and $37 million savings was not material. (TR 213) Some of staff’s concerns are alleviated by the fact that the result of Witness Brubaker’s calculation is not materially different from PEF’s. PEF stated that the error in its short-term analysis did not impact its long-term analysis because this was a separate analysis performed with a different methodology. (TR 46-47, 58) Staff believes it is of particular importance that the error also did not alter the timing and technologies of the units in the two expansion plans. (EXH 2)
Staff has reviewed PEF’s revised short-term cost-effectiveness analysis. Staff agrees with White Springs that PEF’s error in the five-year NPV analysis casts doubt on the specific dollar impact over the contract term. However, staff believes that significant savings will occur during the contract term because it is reasonable to assume that the contracts will defer natural gas-fired capacity, similar to the Franklin capacity. PEF provided sufficient evidence that capacity is needed in 2010 to meet its 20 percent reserve margin, and the units assumed in PEF’s base case analysis appear to be reasonable. (EXH 2) PEF’s 2004 Ten-Year Site Plan included the natural gas-fired combined cycle units in 2010 and 2011 which are deferred in PEF’s analysis of the UPS agreements. (EXH 2) Further, PEF provided adequate evidence that its capacity needs in 2010 could not be met with new or existing coal capacity. (TR 124, 127) Therefore, staff disagrees with White Springs that PEF failed to demonstrate that its “base case” and “altered case” can reasonably be expected to produce the least cost or best alternative. Staff also disagrees with White Springs that “PEF has only demonstrated that the altered case may produce short-term benefits when compared solely to its base case.”
Staff has some concerns that PEF’s long-term analysis shows an expected $5 to $11 million cost from 2010 to 2055. However, staff notes that the NPV outcome of this long-term analysis is highly dependent on the time period used in the analysis, because the timing of several units is altered by the inclusion of the UPS agreements in PEF’s expansion plan. (EXH 2) Staff believes that the up-front benefits over the life of the proposed contracts are more certain than the potential costs based on a 45-year analysis. There is sufficient certainty that significant benefits will occur due to the deferral of natural-gas fired combined cycle technology between 2010 and 2015. PEF’s expansion plan following the contracts through 2055 is much less certain. Therefore, staff would place more credence on the short-term benefits of the contracts than the potential long-term costs.
Staff’s concerns about the potential long-term costs are also alleviated by the important non-price benefits of the contracts. These benefits include: 1) fuel diversity due to the 74 MW of coal capacity; 2) transmission access into Southern’s system and beyond; 3) potential savings from economy energy purchases and sales; 4) increased reliability; and, 5) planning flexibility. These non-price benefits will be discussed further in Issue 3.
In summary, staff believes PEF’s cost-effectiveness analysis is reasonable and supported by the evidence. PEF used an accepted system planning methodology to develop the two expansion plans compared in its analysis, and its base-case mirrors its approved 2004 Ten-Year Site Plan. PEF’s error in its initial analysis casts doubt on the specific short-term savings. However, staff believes that significant savings will occur during the contract term because the contracts should defer natural gas-fired combined cycle capacity. These savings are more certain than the estimated long-term costs. Potential long-term costs are also mitigated by the important non-price benefits associated with the contracts. Given the more certain up-front benefits and additional non-price benefits, staff believes the UPS agreements are worth the risk that an expansion plan that includes the agreements may have a negative $5 to $11 million NPV through 2055.
Issue 2A:
Are the claimed savings associated with the agreements supported by the evidence?
Recommendation:
Yes. PEF’s error in its initial five-year NPV analysis casts doubt on the specific dollar savings from 2010 through 2015. However, it is reasonable to assume that the contracts will defer natural gas-fired combined cycle capacity, resulting in significant savings. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF’s comparative analyses of the self-build and alternative UPS resource plans are based on industry standard techniques with which the Commission is familiar. The annual revenue-requirements analysis demonstrates projected savings of $44 million over the term of the Agreements. However, projected savings are not a prerequisite for Commission approval.
W. SPRGS:
No. PEF first claimed savings under the proposed UPS agreements of $133 million, and subsequently reduced that claim by $90 million. At hearing, Mr. Waters undermined the reliability of this analysis. Furthermore, PEF’s own evidence demonstrates a net detriment to consumers of between $5 and $11 million.
Staff Analysis:
As discussed in Issue 2, PEF revised the NPV benefit during the contract term from $133 million to $44 million. PEF was unable to provide work papers or recreate its flawed analysis. (TR 63, EXH 2) Staff agrees with White Springs that PEF’s error in the five-year NPV analysis casts doubt on the specific dollar savings over the contract term. It is important to note that the error did not impact the timing or technologies of the units in the two expansion plans. (EXH 2) As discussed in Issue 2, staff believes that significant savings will occur during the contract term because it is reasonable to assume that the contracts will defer natural gas-fired capacity, similar to the Franklin capacity.
Issue 2B:
Has PEF adequately identified and justified costs that will be borne by ratepayers?
Recommendation:
Yes. PEF adequately identified and justified the potential costs of the agreements, including capacity, energy, O&M, and fuel transportation costs. It was reasonable for PEF to use Southern’s tariff transmission rates in its analysis. As discussed in Issue 5, recovery of any transmission costs in excess of Southern’s tariff rates, which were not provided in the record, should not be approved at this time. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF appropriately accounted for the costs of the Agreements, including capacity, energy, O&M, fuel transportation and transmission costs. PEF’s analyses provide a true representation of the expected impact on PEF’s customers. The costs are justified based on PEF’s economic analyses and the strategic benefits the Agreements will provide.
W. SPRGS:
No. For example, costs associated with transmission will not be known until the System Impact Study is completed. Similarly, PEF has not performed any natural gas price sensitivity analysis. Record evidence shows that natural gas prices are volatile and PEF has a very poor record of predicting natural gas prices.
Staff Analysis:
PEF compared the costs of the self-build plan to an expansion plan that includes the proposed UPS agreements. Witness Waters delineated the costs in PEF’s analysis, which included “not only the costs of construction, new unit fuel and O&M, and power purchase costs, but system fuel impacts as well. System infrastructure costs, such as fuel handling and transportation, and electrical transmission are also included.” (TR 35) Staff has reviewed PEF’s cost assumptions and believes that the assumptions are reasonable.
PEF did not include costs for any potential transmission upgrades in its analysis. (TR 112) As discussed further in Issue 5, PEF assumed that transmission will be provided at Southern’s embedded rate for Long Term Firm Transmission Service under Southern Company Transmission’s Open Access Transmission Tariff (OATT). (EXH 2, TR 12) Transmission costs may be higher than Southern’s tariff rates if there are system impacts from redirecting transmission; however, the agreements contain provisions which may mitigate these costs. (TR 40-41) Therefore, staff believes it was reasonable for PEF to use Southern’s tariff rates in the analysis. Recovery of any potential transmission costs in excess of the tariff rates will be discussed in Issue 5.
PEF did not include start-up costs in its model. (TR 69, EXH 17) These costs occur when generating units are cycled on and off. (TR 67) The Franklin contract contains a provision which compensates Southern for start costs depending on the number of times the unit is cycled. (TR 68) Witness Waters stated that start costs were not included in the model because the contracts are deferring similar natural gas-fired combined cycle units. He expects that these units would be dispatched in a similar manner as the Franklin unit. Witness Waters states “We are comparing apples-to-apples, so there would be no real net effect on the economics.” (TR 69-70, 84, 264-265) PEF did not provide a comparison of the start-up costs for its own combined cycle units to the start-up pricing required under the Franklin agreement. Nevertheless, staff believes the assumption that the difference in the start costs would not be significant because the generating units being compared are similar is reasonable.
PEF did not perform a natural gas price sensitivity analysis. (TR 96-97) White Springs provided evidence that PEF’s natural gas forecasts have changed dramatically over a relatively short period of time. (EXHS 22, 23, 24) In this instance, staff agrees with Witness Waters that a natural gas sensitivity analysis with higher gas prices would tend to favor the expansion plan that includes the UPS agreements, as this plan includes the 74 MW of coal capacity from the Scherer unit. It is reasonable to assume that the contracts would be replacing similar natural gas-fired capacity. The record indicates that PEF could not place a coal unit in service to meet the 2010 need. (TR 124) Further, PEF has not received any bids from existing coal-fired capacity in its two most recent RFPs. (TR 127)
In summary, staff believes that PEF adequately identified and justified the potential costs of the agreements. PEF appropriately compared the costs of the self-build plan to an expansion plan that includes the proposed UPS agreements. PEF adequately identified the potential costs of the agreements, including capacity, energy, O&M, and fuel transportation costs. It was reasonable for PEF to use Southern’s tariff transmission rates in its analysis. However, as discussed in Issue 5, recovery of any transmission costs in excess of Southern’s tariff rates, which were not provided in the record, should not be approved at this time. PEF also provided adequate justification to assume a zero start cost, and to not perform a gas price sensitivity analysis. As discussed in Issue 2, PEF provided adequate evidence to justify the costs, given the expected savings and non-price benefits over the life of the contract.
Issue 3:
Are PEF's claimed "non-price" benefits of the UPS agreements supported by the evidence and reasonable?
Recommendation:
Yes. The agreements provide several non-price benefits, including: 1) fuel diversity; 2) transmission access; 3) potential savings from economy energy purchases and sales; 4) increased reliability; and, 5) planning flexibility. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. The evidence demonstrates the Agreements will provide important non-price benefits, including fuel diversity, transmission access to economy purchases and sales, increased reliability, cost certainty, potential access to additional coal capacity, and planning flexibility.
W. SPRGS:
No. The claimed non-price benefits are illusory. PEF has conducted no analysis on potential coal capacity available from other sources, PEF’s claim of reliability due to import rights is unreasonable and misleading, and PEF's planning flexibility claim is unsupported by evidence.
Staff Analysis:
Staff agrees with PEF that the UPS agreements have several non-price strategic benefits. These benefits are difficult to quantify; however, staff disagrees with White Springs that these benefits should not be considered. Staff believes these non-price benefits, in particular the transmission rights and access to coal capacity, are essential in determining whether the contracts should be approved.
· Transmission Access and Economy Energy: The UPS agreements allow PEF to exercise its roll-over rights and maintain transmission access to the Southern system and beyond. This provides access to potential economy energy purchases and sales and increases reliability. PEF believes that the UPS agreements will provide the opportunity for increased economy purchases because a portion of the capacity is natural-gas fired. The Franklin unit will not be dispatched over as many hours as a coal-fired unit, providing PEF with excess transmission capacity that may be used to transport economy energy in the hours when PEF is not taking energy from Franklin. (EXH 2) PEF also believes that its rights to the Florida/Georgia interface, while independent of the agreements, may be placed at risk if the contracts are not approved, and if PEF does not use the interface for another purpose. (TR 135-136, 152-153)
· Fuel Diversity: Although the UPS agreements provide less coal capacity than the existing agreements, more coal capacity is provided than under the self-build option. Placing this coal-fired capacity under contract will reduce the exposure of PEF’s ratepayers to fuel price volatility. PEF has also obtained a right-of-first refusal on additional coal capacity to replace all or part of the Franklin natural gas-fired capacity. (EXH 2) Staff disagrees with White Springs that the proposed agreements do not increase fuel diversity because the coal capacity has been reduced compared to the existing agreements. The impact on fuel diversity should be compared to the options available to purchase or place in service in 2010, not based on the coal capacity provided under the existing Southern UPS agreements. White Springs provided no evidence that PEF could place a coal plant in service by 2010 or that additional coal capacity would be available for PEF to purchase. The record indicates that a coal plant would take at least seven years to site and build. (TR 124) PEF has not received bids for capacity from existing coal units in its two most recent RFPs. (TR 127)
· Planning Flexibility: PEF has obtained a right to extend the contracted Franklin capacity to 2017, or it can let the agreement expire. (TR 51) Witness Waters stated that if PEF does extend the Franklin agreement, recovery would be subject to Commission review. (TR 52) The contracts also give PEF additional time to study the cost-effectiveness and feasibility of adding coal-fired capacity. PEF provided staff with information on two recent internal and external analyses of the impact of adding coal-fired capacity to PEF’s system. (EXH 2) PEF assumed that the in-service date of a coal-fired unit would be moved up from year 2017 to 2015 in its expansion plan with the UPS agreements. Finally, the agreements appear to have greater scheduling flexibility than the existing agreements. (EXH 2)
· Reliability: The UPS agreements increase reliability by: 1) adding an outside source for natural gas transportation to fuel the Franklin unit; and, 2) providing access to energy from Southern’s system and beyond. (TR 39)
In conclusion, staff believes that the non-price benefits discussed above are reasonable and provide important potential benefits for PEF and its ratepayers. The fuel diversity and planning flexibility afforded by the agreements are of particular importance due to the volatility and forecasting uncertainty of natural gas prices. The coal-fired capacity from Southern’s Scherer unit will reduce PEF’s ratepayers’ exposure to fuel price volatility, while the timing of the contracts will give Progress the flexibility to defer natural gas-fired capacity and potentially move up the in-service date of a coal-fired unit.
Issue 4:
Who should bear the risk if PEF's claimed cost and "non-price" benefits are not realized, PEF's customers or its stockholders?
Recommendation:
If the Commission approves Issue 7, recovery of capacity and energy costs associated with the agreements should be permitted subject to a finding of reasonableness and prudence of the actual expenses when recovery is requested. Transmission costs in excess of tariff rates and any extension of the Franklin agreement should be subject to further review. (Harlow, McRoy)
Position of the Parties
PEF:
Under long-standing Commission policy, prudently incurred capacity and fuel costs are directly passed through to customers. If the Commission approves the UPS Agreements as reasonable and prudent, PEF should be authorized to recover the energy and capacity costs associated with the Agreements when actual expenses are presented for cost recovery.
W. SPRGS:
PEF’s stockholders should bear the risk that the claimed benefits will fail to materialize, because PEF entered into transmission arrangements associated with these agreements prior to Commission approval. PEF management, as a sophisticated party to the contract negotiations, should remain accountable for contracting decisions resulting in less-than expected benefits.
Staff Analysis:
Staff agrees with PEF that it is Commission policy for purchased power costs which are found to be reasonable and prudent to be recovered from the ratepayers. If the Commission approves Issue 7, recovery of capacity and energy costs associated with the agreements should be permitted through the appropriate cost recovery clauses. Recovery of actual expenses should be subject to a finding of reasonableness and prudence when recovery is requested by PEF.
Staff believes recovery of reasonable and prudent expenses through the cost recovery clauses is appropriate. PEF’s stockholders do not receive earnings on purchased power agreements. Ratepayers will receive all benefits from the up-front savings associated with deferring the need for natural gas-fired capacity. Ratepayers will further benefit from cost savings on economy purchases facilitated by the associated transmission. Profits on economy sales made by PEF from the Southern capacity will be split 80/20 between PEF’s ratepayers and stockholders, if PEF has surpassed its three-year rolling average economy sales threshold. If PEF has not met this threshold, 100 percent of profits from economy sales will be credited to PEF’s ratepayers. (TR 148)
Staff does not believe it is appropriate for ratepayers to bear the risk of transmission costs which have not been identified in the record without further Commission review. As discussed in Issue 5, PEF may experience additional transmission costs due to the need to redirect the transmission path from the Miller to the Franklin Plant. (TR 40-41) Any transmission costs in excess of tariff rates should be subject to further Commission review when actual costs are known and recovery is requested. Likewise, if PEF extends the Franklin agreement, as discussed in Issue 3, recovery should be subject to Commission review. (TR 51-52)
Staff disagrees with White Springs that “PEF’s stockholders should bear the risk that the claimed benefits will fail to materialize, because PEF entered into transmission arrangements associated with these agreements prior to Commission approval.” The agreements contain provisions which mitigate the transmission costs, or allow PEF to terminate the agreements, if transmission costs exceed specified levels. (TR 40-41) Therefore, staff does not believe it was imprudent for PEF to request rollover transmission rights prior to receiving Commission approval for the proposed UPS agreements.
If the Commission approves Issue 7, staff recommends recovery of capacity and energy costs associated with the agreements subject to a finding of reasonableness and prudence of the actual expenses when recovery is requested. Any transmission costs in excess of tariff rates or extension of the Franklin agreement should be subject to a further review by the Commission to determine if PEF’s actions in these instances are reasonable and prudent.
Issue 5:
Is there sufficient reliable transmission available to support the proposed agreements on the Southern system?
Recommendation:
It is reasonable to assume that sufficient transmission will be available to accommodate the agreements. The agreements contain provisions which may mitigate any transmission costs in excess of Southern’s tariff rates; however, total transmission costs will not be known until Southern completes its System Impact Study (SIS) and PEF reacts. Transmission costs above Southern’s tariff rates should not be approved at this time because PEF did not provide evidence of these costs in the record. PEF should be required to file: 1) the results of the SIS study; 2) an estimate of costs in excess of Southern’s tariff rate; and, 3) PEF’s intended response, with the Commission. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. The existing and new purchases are basically equal in magnitude. The Franklin purchase involves a different source, but there is no reason to believe that redirection of PEF’s “rollover” transmission rights cannot be implemented. If sufficient transmission is unavailable, PEF has remedies, including contract termination under certain circumstances.
W. SPRGS:
There is great uncertainty concerning whether sufficient reliable transmission will be available. Southern has not completed its System Impact Study of PEF’s redirected transmission service request. Thus, there is no evidence either that transmission will be available to support the proposed agreements or that, if available, it will be cost-effective.
Staff Analysis:
PEF’s existing UPS agreements with Southern provide for 414 MW from the Miller and Scherer units. These agreements are bundled agreements which include transmission rights on Southern’s system. (TR 56, EXH 2) PEF has “rollover rights” to this transmission because PEF was purchasing through this transmission path prior to the FERC ruling to unbundle transmission rights. In other words, PEF is “first-in-line” for these transmission rights. (TR 141-143)
PEF has requested, and Southern has affirmed, PEF’s rollover rights. (TR 142) However, because PEF will be purchasing from the Franklin unit rather than the Miller unit under the new agreements, the transmission path must be redirected. Consequently, on April 12, 2005, Southern notified PEF that a SIS would be required to determine available capacity and potential upgrade costs. On April 18, 2005, PEF signed the SIS agreement and paid Southern $10,000 to perform the study. (EXH 2) PEF expects to receive the completed study on or about June 25, 2005. (TR 113) According to Witness Waters, under Southern Company Transmission’s OATT, PEF must come to a final transmission agreement with Southern within 15 days of receiving the results of the SIS if there is no impact from redirecting the transmission. PEF also stated that “[T]he interface allocation that currently accommodates the UPS purchases from Southern is sufficient to accommodate the proposed purchases.” (TR 42)
PEF assumed a transmission rate of $1.94/kW-month in its cost-effectiveness analysis. This is equivalent to the embedded rate for Long Term Firm Transmission Service under Southern Company Transmission’s OATT. (EXH 2, TR 12) PEF did not include costs for any potential transmission upgrades in its analysis. (TR 112)
Witness Waters stated that he has no reason to believe sufficient transmission will not be available from the Franklin plant to PEF’s system because the Franklin plant is “essentially between Miller and us.” (TR 114) Given the location of the Franklin plant relative to the Miller plant, staff believes it is reasonable to assume that there will not be significant costs for transmission upgrades. However, if the SIS does conclude that there are system impacts, there are provisions in the contract which mitigate PEF’s exposure to transmission costs in excess of the tariff rate. For example, Section 7.4.4 of the contract provides Southern with the option “of offering to sell, including by reassignment, up to the required amount of transmission service, and/or offsetting any transmission costs above the OATT rate.” (TR 13) If a specified portion of the transmission is then offered to PEF at above the tariff rate, PEF has the option to terminate the agreement. (TR 40-41) Further, the Scherer and Franklin UPS agreements also contain sections which tie the agreements together. Therefore, if PEF determines that it is appropriate to terminate the Franklin agreement because sufficient transmission is not available, or necessary transmission upgrades are too costly, the Scherer Agreement would also be terminated. A final transmission agreement must be reached by February 2006, unless both parties agree to extend the deadline. (EXH 2)
Staff believes that given the location of the Franklin plant relative to the Miller plants, it is reasonable to assume that sufficient transmission will be available to accommodate the proposed UPS agreements; however, additional transmission costs may occur if Southern’s SIS finds that there are system impacts from redirecting transmission from the Miller path to the Franklin path. Staff agrees that the UPS agreements contain provisions which provide PEF with options to mitigate these potential costs. These potential costs will not be known until Southern completes its SIS study and PEF acts on the results of the study. Staff also notes that PEF’s cost-effectiveness analysis did not include transmission costs in excess of Southern’s tariff rate. Therefore, if the Commission approves PEF’s petition for the proposed UPS agreements, staff believes it is inappropriate to include approval of transmission costs in excess of Southern’s tariff rates because PEF did not provide evidence of these costs in the record. PEF’s Witness Waters agreed, in response to a question from Chairman Baez, that it is his understanding that any excess transmission costs would be at risk if PEF requested recovery. (TR 256) Further, staff believes PEF should be required to file: 1) the results of the SIS; 2) an estimate of costs in excess of Southern’s tariff rate; and, 3) PEF’s intended response to the study, with the Commission as soon as the SIS is completed and PEF determines its response. This will put the Commission on notice of any potential additional transmission costs that PEF may request recovery for in the future.
Issue 6:
Has PEF demonstrated that the UPS agreements would postpone the need for other generation?
Recommendation:
Yes. PEF provided evidence that the capacity is needed to maintain PEF’s 20 percent reserve margin. It is reasonable to assume that the contracts will defer natural gas-fired combined cycle capacity, similar to the Franklin capacity. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF’s analyses demonstrate the Agreements will defer two combined cycle units. Indeed, White Springs admits that “PEF’s evidence appears to demonstrate that the UPS Agreements will postpone the need for other generation.
W. SPRGS:
Although PEF’s evidence appears to demonstrate that the agreements will postpone the need for other generation, that does not support the reasonableness of the proposed agreements. Adding additional capacity from any source – whether self-build, other PPAs or demand side management – would equally postpone the need for other generation.
Staff Analysis:
PEF provided sufficient evidence that the 424 MW of capacity provided by the UPS agreements is needed to maintain PEF’s 20 percent reserve margin. PEF’s reserves would fall from 23 percent to approximately 18 percent in 2010 if the current contract capacity is not replaced. (EXH 2)
PEF’s analysis showed that during the term of the contracts, two natural gas-fired combined cycle units would be deferred. The first unit would be deferred from 2010 until 2011, while the second unit would be deferred from 2012 through 2018. (TR 154; EXH 2) PEF’s 2004 Ten-Year Site Plan, which did not assume the continuation of the proposed agreements, included 2010 and 2012 combined cycle units. (EXH 2) Staff has some concern that PEF’s 2005 Ten-Year Site Plan, which includes the UPS agreements, shows a similar expansion plan to the 2004 Ten-Year Site Plan, which did not include the agreements. (EXH 2) However, Witness Waters stated that the plans are similar due to an approximately 300 to 400 MW expansion in PEF’s peak demand and load forecast. (TR 155) Staff agrees with White Springs that the record appears to show that the contracts will defer the need for generation. Staff also believes it is reasonable to assume that the avoided generation will be natural gas-fired combined cycle capacity, similar to the Franklin capacity. PEF adequately demonstrated that coal capacity cannot be placed in service or purchased in time to meet the 2010 need. (TR 124, 127) Therefore, staff recommends that the record shows that the agreements will defer natural gas-fired combined cycle capacity, which is needed to maintain PEF’s 20 percent reserve margin.
Issue 7:
Should the Commission approve the UPS agreements for cost recovery purposes?
Recommendation:
Yes. PEF has adequately demonstrated that entering into the proposed agreements is a reasonable and prudent action at this time, with significant economic and non-price benefits over the life of the agreements. Given the more certain up-front benefits, the agreements are worth the risk that an expansion plan that includes the agreements may have a negative $5 to $11 million NPV through 2055. Delaying approval may place the agreements, in particular the transmission access and coal capacity, at risk. PEF should be required to file: 1) the results of the SIS; 2) an estimate of costs in excess of Southern’s tariff rate; and, 3) PEF’s intended response. (Harlow, McRoy)
Position of the Parties
PEF:
Yes. PEF demonstrated that the Agreements are economical and will provide important strategic benefits. There is no reason to delay. PEF and its customers are protected if the SIS concludes that transmission upgrades are necessary; and speculation regarding pending FERC investigations do not provide a basis for delay.
W. SPRGS:
No. PEF failed to demonstrate that the UPS agreements are reasonable and prudent, given that PEF did not consider alternatives to the agreements, failed to reasonably demonstrate the purported cost savings and economic efficiencies of the proposed agreements, and failed to demonstrate that the agreements are lowest-cost considering all factors.
Staff Analysis:
As discussed in Issues 1 through 6, PEF has adequately demonstrated that entering the proposed UPS agreements with Southern is a reasonable and prudent action at this time. The contracts will provide significant economic benefits over the life of the contracts due to the deferral of natural gas-fired capacity. The agreements also provide important non-price benefits, including: 1) fuel diversity; 2) transmission access; 3) potential savings from economy energy purchases; 4) increased reliability; and, 5) planning flexibility. Given these more certain up-front economic and non-price benefits, staff believes it is worth the risk that the estimated $5 to $11 million long-term cost through 2055 materializes. Delaying approval of the contracts may place the agreements, in particular the transmission access and coal capacity, at risk.
As discussed in Issue 5, transmission costs may be higher than Southern’s tariff rate if there are system impacts from redirecting transmission. Ratepayers are somewhat protected by the contract provisions which may mitigate these costs; however, total transmission costs will not be known until Southern completes its SIS and PEF acts on the results of the study. Transmission costs above Southern’s tariff rates should not be approved at this time because PEF did not provide evidence of these costs in the record. PEF should be required to file: 1) the results of the SIS; 2) an estimate of costs, if any, in excess of Southern’s tariff rate; and, 3) PEF’s intended response to the results of the study, with the Commission as soon as the SIS is completed and PEF determines its response. Also, as discussed in Issue 3, if PEF extends the Franklin agreement, the associated costs should be subject to further review.
Therefore, staff recommends that the Commission should approve the UPS agreements for cost recovery purposes. Given the significant economic and non-price benefits over the life of the agreements demonstrated by PEF, staff believes that entering into the proposed agreements is a reasonable and prudent action at this time.
Issue 8:
Should this docket be closed?
Recommendation:
The docket should be closed after the time for filing an appeal has run. (Vining)
Staff Analysis:
The docket should be closed 32 days after issuance of the order, to allow the time for filing an appeal to run.