Source: https://texreg.sos.state.tx.us/public/readtac$ext.TacPage?sl=T&app=9&p_dir=P&p_rloc=125567&p_tloc=29648&p_ploc=14771&pg=3&p_tac=&ti=16&pt=2&ch=25&rl=263
Timestamp: 2019-05-27 09:13:05
Document Index: 390708797

Matched Legal Cases: ['§25', '§39', '§39', '§101', '§39', '§39', '§39']

SUBCHAPTER J COSTS, RATES AND TARIFFS
DIVISION 2 RECOVERY OF STRANDED COSTS
RULE §25.261 Stranded Cost Recovery of Environmental Cleanup Costs
(a) Purpose. The purpose of this section is to:
(1) establish the procedures and criteria for determining the amount of stranded cost recovery electric utilities and affiliated power generation companies shall receive for environmental cleanup costs incurred to improve air quality in the state pursuant to Public Utility Regulatory Act (PURA) §39.263; and
(2) minimize stranded costs associated with the implementation of PURA §39.264.
(b) Applicability. This section applies to:
(1) electric utilities that seek to recover capital costs incurred during the period January 1, 1999 to April 30, 2003 to improve air quality; and
(2) affiliated power generation companies that seek to recover capital costs incurred during the period January 1, 2002, to April 30, 2003 to improve air quality.
(c) Definitions. The following words and terms, when used in this chapter, shall have the following meanings unless the context clearly indicates otherwise:
(1) Conservation Commission - The Texas Natural Resource Conservation Commission.
(2) Cost of replacement generating capacity - The cost of replacing generating capacity lost through retirement of an electric generating facility. The annual cost of replacement generating capacity will be calculated using the following equation:
(3) Electric generating facility - A facility that generates electric energy for compensation and that is owned or operated by a person in this state, including a municipal corporation, electric cooperative, or river authority.
(4) Expected remaining life - The estimated life in whole years of the generating facility from May 1, 2003 as estimated by the utility at the time of filing its application for approval of its cost-effectiveness determination plan.
(5) Net book value - The original cost of an asset less accumulated depreciation.
(6) Offset - The allocation of emission allowances or credits from one facility to another facility in the same region.
(7) Operations and maintenance (O&M) escalator - The applicable operations and maintenance (O & M) escalator set forth in the unbundling cost of service rate filing package. The O& M escalator for a gas-fired electric generating unit shall be 2.0% and the O & M escalator for a coal-fired electric generating unit shall be 1.0%. Notwithstanding the foregoing, the O & M escalator for TNP One shall be 1.5%.
(8) Region - The East Texas Region, West Texas Region, or El Paso Region, as defined by the conservation commission at 30 TAC §101.330.
(9) Retirement - The permanent removal from service of an electric generating facility.
(10) Retrofit - The installation of control technology on an electric generating facility to reduce the emissions of nitrogen oxide, sulfur dioxide, or both.
(11) Retrofit Cost - The net present value of the total capital cost and operating and maintenance cost to operate an electric generating facility after installation of a retrofit. The cost of a retrofitted unit shall be expressed in net present value dollars as of 2003 using the equation VALUE = (ECCR + O & M+ FUEL + O & M R + OE), where:
(A) VALUE = net present value in 2003 over the expected remaining life of a retrofitted unit;
(B) ECCR = net present value of the estimated capital cost of retrofit as of 2003 and the net present value as of 2003 of the expected capital cost of environmental controls installed no later than 2010 to meet future regulations for emissions. The commission will adopt a methodology for calculating the capital cost of environmental controls to meet future regulations for emissions.
(C) O & M= net present value as of 2003 of operation and maintenance cost of unit without retrofit, calculated as O & M= (((average of plant non-fuel fixed O & M cost reported for the most current five calendar years on FERC Form 1) x ((maximum generator nameplate rating as reported for the unit on Form EIA-411 or if not available on Form EIA-411, then the rating as reported to the commission) / (sum of the maximum generator nameplate rating as reported for all units comprising the plant at which such unit is located on Form EIA-411 or if not available on Form EIA-411, then the rating as reported to the commission))) + ((average of plant non-fuel variable O & M cost, expressed in $/MWh, reported for the most current five calendar years on FERC Form 1) x (unit generation for 2003, calculated as the average generation in MWh for the most current five years as reported on Form EIA-767 or if not available on Form EIA-767, then the generation as reported to the commission, declining for the years 2004 and thereafter at the rate of 2.0% per year)) escalated by the O & M Escalator for each year subsequent to the year in which the cost effectiveness determination was filed;
(D) FUEL = Cost of fuel, calculated as net present value as of 2003, over the expected remaining life of the retrofitted unit, using the equation FUEL = HR x G x Gas where:
(i) HR = unit heat rate, calculated as the average of the heat rate reported for the most current five calendar years on Form EIA-411 or if not available on Form EIA-411, then the heat rate as reported to the commission, expressed in mmBtu/MWh;
(ii) G = unit generation, calculated for 2003 as the average generation in MWh reported for the three most current calendar years on Form EIA-767 or if not available on Form EIA-767, then the generation as reported to the commission, declining for the years 2004 and thereafter at the rate of 2.0% per year; and
(iii) Gas = forward natural gas prices as adopted for the ECOM model in August, 2000 by the commission;
(E) O & MR = Net present value as of 2003 of estimated additional operating and maintenance cost resulting from the retrofit, beginning with costs for calendar year 2003 and escalated each year at 2.0% per year and the net present value as of 2003 of the expected operating and maintenance cost of environmental controls to meet future regulations for emissions beginning with costs for the estimated year of installation and escalated each year through 2010 at 2.0% per year. The commission will adopt a methodology for calculating the O & MR cost of environmental controls to meet future regulations for emissions;
(F) OE = Ownership effect, calculated as the net present value as of 2003, over the expected remaining life of the retrofitted unit, using the equation OE = VALUE(PT + PI + CAPIMP - OMTA - CAPIMPDEP - DEPTAXBEN) where:
(i) PT = annual property tax, adjusted for income tax benefit = (applicable property tax rate) x (ADJECCR) x (1 - income tax rate) where ADJECCR is equal to ECCR reduced to reflect any property tax exemption for which the unit might qualify;
(ii) PI = annual property insurance, adjusted for income tax benefit = (applicable property insurance rate) x (ECCR) x (1 - income tax rate);
(iii) CAPIMP = annual continuing capital improvements, adjusted for income tax benefit = (1.25% of the sum of the net book value plus improvements) x (1- income tax rate);
(iv) OMTA = annual income tax benefit on O & MR = (income tax rate) x (estimated additional operating and maintenance cost of the retrofit for the applicable year);
(v) CAPIMPDEP = annual tax depreciation on CAPIMP; and
(vi) DEPTAXBEN = (income tax rate) x (annual tax depreciation on ECCR).
(12) Transportation equipment - A rail spur at a lignite-fired electric generating facility installed to receive deliveries of western coal. Transportation equipment does not include rail cars and unloading facilities.
(1) Qualifying retrofit costs. To be eligible for recovery as invested capital pursuant to PURA §39.263, a retrofit cost must be:
(A) reasonable and prudent;
(B) incurred in carrying out the most cost-effective alternative for improving air quality as approved pursuant to this section;
(C) incurred to reduce or offset emissions by an amount and at a location that is consistent with the air quality goals and policies of the conservation commission;
(D) incurred to offset or reduce the emission of airborne contaminants from an electric generating facility, where:
(i) the emission reduction or offset is determined by the conservation commission to be an essential component in achieving compliance with a national ambient air quality standard. For purposes of this section, any emission reduction or offset achieved by an electric utility or affiliated power generation company to comply with conservation commission regulations at 30 TAC Chapter 117 is deemed to have been determined by the conservation commission to be an essential component in achieving compliance with a national ambient air quality standard; or
(ii) the reduction or offset is necessary for an unpermitted electric generating facility to obtain a permit in the manner provided by PURA §39.264; and
(E) associated with the engineering, procurement, or installation of pollution control equipment or transportation equipment, or the purchase of emissions allowances.
(2) Qualifying retirement costs. Retirement costs may be included in the electric generating facility's stranded cost determination if retirement of the facility is the most cost-effective alternative, taking into account the cost of replacement generating capacity. Recoverable retirement costs are the net book value of the facility, including retirement costs, less salvage value.
(3) When costs incurred. For purposes of this section, the electric utility or affiliated power generation company has incurred costs if it has expended funds or has committed to expend funds under the terms of a written agreement.
(4) Operating and maintenance costs. This section does not authorize the recovery of operating and maintenance costs or the capital cost of a new electric generating facility.
(5) Apportionment of reductions. As provided in this paragraph, the commission may apportion the capital invested to reduce emissions of nitrogen oxides, sulfur dioxide, or both, among one or more entities owning facilities located in the same region. The capital investments for which recovery is sought must have been incurred pursuant to a written agreement between the entities executed prior to the date any such costs were incurred. The commission may not apportion capital costs under this provision unless the criteria of paragraph (1) of this subsection are met for each electric generating facility seeking capital cost recovery. Capital costs shall be apportioned by prorating the total capital invested between entities on the basis of reductions of nitrogen oxides, sulfur dioxide, or both, realized at each participating entity's facilities in the region.
(e) Request for approval of cost-effectiveness determination.
(1) Application. On or before January 10, 2003, an electric utility or affiliated power generation company that seeks recovery of capital costs pursuant to this section shall file an application for a determination that its plan for meeting the requirements of PURA §39.264 and the regulatory programs designed to achieve compliance with national ambient air quality standards are cost-effective under this section. No more than one application may be filed for generating facilities owned by the same electric utility or affiliated power generation company in the same region. The application shall include the information specified in subparagraphs (A) - (H) of this paragraph.
(A) Description. A general description of the generating facility, including but not limited to:
(i) net generating capacity in megawatts;
(ii) type of fuel used for electric generation;
(iii) the county and region in which each facility addressed in the application is located;
(iv) average capacity factor for the three most current calendar years as reported to the commission;
(v) generation in megawatt-hours for the three most current calendar years, as reported on Form EIA-767 or if not available on Form EIA-767, then as reported to the Public Utility Commission of Texas;
(vi) the expected remaining life of the facility; and
(vii) any other information required to perform the analysis prescribed by this section.
(B) Total emissions. The total annual emissions (in tons) of nitrogen oxides and sulfur dioxide:
(i) for the year 1997;
(ii) for the most recent calendar year for which data is available;
(iii) that is expected for the first calendar year after the implementation of the air quality improvement strategies for which cost recovery will be requested; and
(iv) for the calendar years 2003 through 2005.
(C) Allocated emissions allowances. The number of emission allowances allocated to the electric generating facility by the conservation commission.
(D) Capital cost estimate. The total amount of qualifying capital costs for each option evaluated by the electric utility or affiliated power generation company.