In a bid to boost generating capacity at its Polk power plant, Tampa Electric on Sept. 12 applied at the Florida Public Service Commission for approval to license, construct and operate Polk Units 2-5 as a natural gas-fired combined cycle (NGCC) power plant.
Unit 1 at Polk, a coal and petroleum coke gasification facility, is not involved. The site currently consists of Unit 1, a 220-MW IGCC, and four combustion turbines (CTs) totaling a net 604 MW in the summer. The Polk 2-5 revamp project is expected to generate a net 1,195 MW in winter and 1,063 MW in the summer. Tampa, a unit of TECO Energy (NYSE: TE), first announced this project on Aug. 22.
“Polk 2-5 will result from the conversion of Tampa Electric’s four existing CT generating units, Polk 2 through 5, at Polk Power Station into a modem NGCC generating facility, thereby making efficient and economic use of what is otherwise waste heat exhausted from the existing CTs,” TECO said in the application. The energy from this waste heat is captured in four new heat recovery steam generators (HRSGs). The steam created in the HRSGs is directed to a single steam turbine generator. With additional supplemental firing of the HRSGs the single steam turbine will generate 459 MW of summer capacity and 463 MW of winter capacity. This generation will allow Tampa Electric to meet a projected need for additional generating resources that begins in 2017 and increases each year thereafter.
The Polk 2-5 project, as the company’s next capacity addition, will provide significant savings to Tampa Electric’s customers compared to the other “self-build” options, Tampa said. In addition, the project will provide savings over the most cost-effective alternative from among the various responses received in a request for proposals (RFP). Customers will save about $132.4m in cumulative present worth revenue requirements in 2012 dollars over the most favorable proposal from the RFP responses, the company added.
Project would drive up the plant’s capacity, thermal efficiency
Polk 2-5 will be a NGCC facility consisting of four CTs, four HRSGs with incremental supplemental firing and a single steam turbine arranged such that each of the four existing CTs will be coupled with a HRSG. The output of the four HRSGs would drive a single steam generator, which is referred to as a 4x4x1 configuration. The technology is a combination of a combustion turbine (Brayton) cycle and a traditional steam (Rankine) cycle technologies. The combination of these two technologies allows for thermal efficiency of almost 50%.
Capturing of waste heat from the existing Polk CTs 2-5 will generate an incremental net 352 MW of electricity in winter at 32 degrees Fahrenheit and 339 MW in the summer at 92 degrees Fahrenheit. The HRSGs installed at Polk 2-5 will also utilize supplemental firing of natural gas, also known as duct burners, to generate additional steam and provide 120 MW (summer) and 111 MW (winter) of peaking capacity that will offset the need for future peaking unit capacity.
The project is also being designed to incorporate about 30 MW of solar energy in the form of steam from solar thermal collectors located at the Polk site. The integration of steam produced via solar collectors into a combined cycle plant is known as a solar hybrid system since it uses the existing combined cycle steam turbine rather than a separate turbine dedicated to solar use. “This is more cost-effective than stand-alone solar and the HRSG supplemental firing creates a back-up and improves reliability,” Tampa said.
The project is being designed to allow operation of each CT in either simple cycle or combined cycle mode. This will provide operating flexibility and will allow the facility to serve both intermediate and peaking load requirements.
Polk CTs 2 and 3 currently have dual fuel capability and are able to utilize either natural gas or distillate oil. Polk CTs 4 and 5 will be permitted to have dual fuel capability. Dual fuel capability improves reliability by significantly minimizing, if not eliminating, fuel supply risk, the utility said. The project will utilize Tampa Electric’s existing natural gas commodity portfolio, storage, pipeline capacity and infrastructure along with backup oil capability and storage.
Operation of the planned combined cycle facilities at times when the existing CTs would not otherwise be operating reduces overall system fuel and purchased power costs due to the high efficiency of the new combined cycle unit.
Tampa added that it currently possesses both physical and contractual flexibility for gas delivery in its portfolio. This provides flexibility in procuring and allocating natural gas using both the Florida Gas Transmission (FGT) pipeline system and Gulfstream Pipeline LLC. Polk is physically connected to the FGT system as a Primary Delivery Point. Tampa Electric’s gas-fired H. L. Culbreath Bayside plant can be supplied from either FGT or Gulfstream and Tampa Electric currently has multiple agreements with both FGT and Gulfstream.
Polk project cost comes in at $706.6m
The total in-service cost estimate for the Polk 2-5 project is $706.6m, which includes overnight construction costs as well as escalation, transmission costs and AFUDC. Cost estimates are based on a preliminary design completed by the engineering firm of Black and Veatch, which has gotten multiple quotations from major equipment manufacturers and has validated current pricing for commodities and labor in the central Florida area, Tampa noted.
After taking into account existing power plant unit capacity, firm purchased power agreements (PPAs), and the most recent Ten Year Site Plan load forecast that considers demand side management (DSM), conservation and renewable energy alternatives, Tampa requires 294 MW of extra generating capacity to maintain system reliability requirements beginning in 2017. Without extra capacity to maintain its 20% reserve margin reliability criterion, Tampa said its 2017 summer reserve margin is projected to fall to 12.5%. Utilizing a recently updated load, DSM and fuel forecast, and taking into account various other factors, Tampa still requires an additional 205 MW of capacity to maintain system reliability requirements beginning in 2017.
Peak demand for the summer of 2012 is forecasted to be 3,993 MW, increasing to 4,331 MW in 2021, an average increase of 38 MW per year. Tampa meets its resource needs through its own power units, purchased power and DSM. Tampa’s generating resources are located at three primary sites (including the Big Bend coal plant) that are distributed geographically throughout its service territory and as of summer 2012, they along with firm PPAs totaled about 4,909 MW (summer) of capacity.
Tampa said it has PPAs with a variety of suppliers totaling 594 MW (summer) for 2012. Tampa Electric also has a contract to purchase firm cogeneration capacity totaling 23 MW in 2012. Tampa Electric requires additional supply resources by 2017 to replace the purchased power contracts as all but one 121-MW contract expire prior to January 2017.