Public Service Co. of Colorado in a Nov. 26 filing at the Colorado Public Utilities Commission argued at various points for a purchase of gas-fired generating capacity at the Brush power plant and against how some other parties want to treat the shutdown of coal units at the Arapahoe and Cherokee power plants.
The arguments by PSCo, a unit of Xcel Energy (NYSE: XEL), were in a combined proceeding for three separate cases: for the purchase of the Brush facilities; for approval of its 2011 Electric Resource Plan (ERP); and issues related to the shutdown of the coal-fired Arapahoe Unit 4. Its wide-ranging arguments covered various related issues, like how it purchases independent power for its system.
The to-be-acquired Brush 1, 3 and 4 facilities are currently subject to Purchase Power Agreements (PPAs) with Public Service. PSCo now wants to purchase these facilities for about $75m. The purchase will provide needed and reliable peaking capacity (211 MW summer, 237 MW installed) for approximately $356/kW (summer rating), the utility pointed out.
“This transaction creates substantial customer savings and compares favorably to alternatives on many bases,” the utility argued. Among other things, the purchase price is only one-third of the cost of new construction of similar units ($829-$1,076/kW), making these low-cost older units ideal as light-duty, low net-capacity-factor peakers, the utility said.
PSCo proposes to depreciate these units on its books, assuming a 45-year useful life from the time the units were refurbished and installed in their current configuration. This is consistent with virtually all smaller natural gas facilities in Xcel’s system. Despite the significant benefits, the utility noted that commission staff recommends that the commission reject the purchase.
PSCo argues with commission staff over remaining lifespan of units
“Staff states as grounds its concern that the units may not last as cost-effective generating resources for their entire 45-year useful life,” the utility said. “Staff asserts that the Company did an inadequate job of disclosing the age of the Brush facilities and from this claim assumes that the Company’s due diligence effort was inadequate. Staff concludes that the transaction is too risky because these units are older and Staff is concerned that the units may not remain cost-effective generation for the Company’s proposed useful life.”
The company’s due diligence effort for this purchase was extensive, thorough, and fully disclosed, PSCo countered. “We were fully aware of the age and condition of these units during due diligence,” it said. “We had qualified personnel review the records and documents provided by the owner and performed on site inspections. Over 120 person hours were spent performing the due diligence of the Brush units. The combined experience of the employees that performed the due diligence is over 50 years. Their experience includes engineering, maintenance, and operation of power plants.”
Staff further implies that the company intentionally withheld important information about the age of the units. Yet, the application provided a description of the assets being purchased and their requested rate treatment as called for by the commission’s requirements.
“We provided all information requested in discovery pertaining to the Brush facilities, including complete access to the operation and maintenance records of the units and the Black and Veatch independent engineering report which made clear the age and good condition of the units,” the utility said. “We also fully addressed the issue of unit age in our Rebuttal.”
Staff’s recommendation that the remaining useful life of these units is only 10-15 years from today is unreasonably short and is inconsistent with PSCo’s extensive experience with smaller, older units, the utility said. “To place our differences with Staff into context, the Company’s proposal of 45 years useful life from current in-service yields remaining useful lives of 22 to 34 years,” it added. “Virtually all of the smaller and older natural gas units on the Xcel Energy system have operating lives consistent with the 45-years we propose.”
Issues also in play about Arapahoe 4’s usefulness as a gas unit
Also as part of this combined case, Public Service has applied for commission approval in this Phase 1 consolidated docket to retire Arapahoe 4 by the end of 2013, if and only if the commission also approves:
- a new ten-year Power Purchase Agreement with SWG Arapahoe LLC under which Public Service will purchase the output from Southwest Generation‘s (SWG) gas-fired Arapahoe units 5, 6 and 7 from 2014 through 2023 (the Arapahoe PPA); and
- a natural gas sales agreement with SWG Fountain Valley Gas LLC, under which Public Service will sell natural gas for SWG’s Fountain Valley generation facility (the Fountain Valley GSA) (collectively the company’s “Proposed Arapahoe Transaction”).
“To be clear, if the Commission does not approve both the Arapahoe PPA and the Fountain Valley GSA, Public Service withdraws its application for approval, in Phase 1, of the early retirement of Arapahoe 4,” the utility wrote. “If the Commission denies approval of the Arapahoe PPA and/or the Fountain Valley GSA, then Public Service would seek to retire Arapahoe 4 prior to year end 2023 only if a qualifying bid made in response to the Company’s All Source RFP in Phase 2 of this proceeding showed ratepayer savings over the continued operation of Arapahoe 4.”
Arapahoe 4 is an almost fully-depreciated coal plant that can burn natural gas. Its heat rate is competitive with many gas-fired units on the Public Service system, the utility noted. It will be very difficult for a bidder in Phase 2 to offer Public Service cheaper generation than Arapahoe 4, particularly given the expectation that Arapahoe 4 will now be used primarily for peaking power as a gas-fired facility, it added.
“To compete against Arapahoe 4, an [independent power producer] would need to provide a very low-cost capacity bid from an existing gas-fired plant with a better heat rate than Arapahoe 4,” the utility argued. “In our 2011 ERP, we proposed to test the market to see if any bidders could beat Arapahoe 4 through an initial screening of bids against continued operation of Arapahoe 4 on gas. We believe that there are only three companies in a position to successfully bid against Arapahoe 4: SWG; Thermo Power; and, Brush Power. By early 2012, Brush Power had already approached us to see if the Company wished to acquire Brush units 1, 3 and 4.”
In ERP dockets, the issue generally is how the forecasted resource need of the utility is to be met. Even though the ERP rules do not contemplate it, Public Service said it is comparing two existing resources -Cherokee 4 and Arapahoe 4 – against replacement generation as a continuation of the evaluation that was undertaken under the Clean Air-Clean Jobs Act (CACJA).
In that CACJA docket, Public Service was required under state law to submit a plan that reduced emissions from a minimum of 900 MW of its coal plants. That statute provided that, at the utility’s discretion, the plan could include various options, including conversion of coal-fired generation to run on natural gas. In its decision modifying Public Service’s CACJA plan, the commission approved the conversion of Arapahoe 4 and Cherokee 4 to run on natural gas through their useful lives, but requested that the company evaluate whether other alternatives might be more cost effective than fuel-switching coal units to natural gas.
Public Service noted that it did not object to this commission modification to the plan because it did not require Public Service to remove these two units entirely from the company’s assumed existing resources in its resource plan. Incremental transmission studies conducted after the commission’s CACJA decision indicate that the must-run conditions assumed for Arapahoe 4 and Cherokee 4 during the CACJA hearings are not necessary, the utility pointed out. These new transmission study results go a long way toward addressing the commission’s concerns as to the inefficient use of natural gas in relatively high heat rate plants. By removing the must run constraints on these two units, they can now serve a role in the company’s dispatch stack as low-cost, gas-fired peaking units.
SWG deals originated in effort to find alternatives to Arapahoe 4 gas switch
To further meet the commission’s directives as to continued operation of Arapahoe 4 on gas, Public Service sought proposals from the two IPPs in a position to cost-effectively compete with operating Arapahoe 4 on natural gas to determine whether either of them could create ratepayer savings. This effort resulted in the Proposed Arapahoe Transaction. If the commission approves the company’s Proposed Arapahoe Transaction, then Arapahoe 4 will be retired at year end 2013. If the commission does not approve the Proposed Arapahoe Transaction, Public Service proposes to meet the commission’s CACJA directives for both Arapahoe 4 and Cherokee 4 through a two stage modeling process.
In the first stage, all bids received in response to an All Source RFP would be allowed to compete individually and collectively against Arapahoe 4 and Cherokee 4. Three separate cases would be prepared: Arapahoe 4 (109 MW) retired year end 2013; Cherokee 4 retired year end 2017 (352 MW); and Arapahoe 4 and Cherokee 4 (461 MW) retired at year end 2013 and 2017, respectively. Portfolios of bids would be developed to fill resulting capacity shortfalls and the Strategist computer model would be configured to consider replacements that provide capacity within +/-20 MW of these MW ratings. Surplus capacity credits and replacement capacity costs for shortfalls in capacity would be accounted for.
Any portfolios that show lower cost than operating either Arapahoe 4, Cherokee 4, or both would be vetted to determine whether the portfolios comply with the commission’s criteria of meeting or exceeding the emissions reductions achieved through the operation of Arapahoe 4 and Cherokee 4 on natural gas. “If any of the bids, singly or in combination, can meet the above criteria, they would be selected and used in all model runs in the second evaluation stage where the Company fills our incremental RAP needs,” the utility said. “If Arapahoe 4 and/or Cherokee 4 are displaced by bids in the first stage, the costs of operating Arapahoe 4 and/or Cherokee 4 for their remaining useful lives will be compared against bids in the second stage for filling the incremental resource needs during the RAP.”
If either Arapahoe 4 or Cherokee 4 are replaced during the first stage evaluation these units are assumed to continue on in the second stage evaluations. If new contracted or built resources are the more cost-effective way to meet the utility’s resource need, Public Service has agreed that it will retire Arapahoe 4 and/or Cherokee 4 early. However, Public Service said it has no concerns about operating either Cherokee 4 or Arapahoe 4 on natural gas through their useful lives and that these units represent inexpensive peaking power. It is important that Arapahoe 4 and Cherokee 4 remain in the company’s portfolio in order to provide price discipline to the market, the utility said.
There was some suggestion through opposing counsel’s questions at a case hearing that Arapahoe 4 and Cherokee 4 should be removed from Public Service’s existing resource mix, that 461 MW of additional resource “need” should be put in play, and that Public Service should be required to “bid” into the All-Source RFP the continued operation of Arapahoe 4 and Cherokee 4. “This suggestion runs contrary to Commission rules and the Commission neither contemplated nor ordered this in its CACJA decision,” the utility said.