Opinion ID: 895304
Heading Depth: 2
Heading Rank: 1

Heading: Overview of Chapter 39[1]

Text: The Legislature in 1999 [2] overhauled the Public Utility Regulatory Act (PURA or Act) to create a fully competitive electric power industry in Texas. [3] As part of this restructuring, utilities were required, not later than January 1, 2002, to split into three distinct units: (1) a power-generation company, (2) a retail electric provider, and (3) a transmission and distribution utility. [4] After that date, retail consumers could choose among competing retail providers. [5] Rates charged by the transmission and distribution utility continue to be regulated by the Public Utility Commission (PUC or Commission). [6] The Legislature recognized that utilities had made investments in power-generation assets that produced a reasonable return under the existing regulated environment but might well become uneconomic and thus unrecoverable in a competitive, deregulated electric power market. [7] The Act thus allows utilities to recover these stranded costs, which consist generally of the portion of the book value of a utility's generation assets that is projected to be unrecovered through rates that are based on market prices. [8] The Act deregulated the market in phases. Retail rates were frozen from September 1, 1999 until January 1, 2002. [9] Section 39.201 directed transmission and distribution utilities to file, on or before April 1, 2000, proposed tariffs that included nonbypassable delivery charges to retail electric providers. [10] It also directed the PUC to approve rates as of January 1, 2002. [11] The nonbypassable delivery charges included a competition transition charge (CTC) based on an estimate of stranded costs projected to exist at the end of the freeze period on December 31, 2001. [12] The CTC is nonbypassable in that with limited exceptions, all retail electric customers in an existing utility's service area will pay charges to allow that utility to recover stranded costs regardless of whether those customers purchase their electricity from that utility, switch to one of its competitors, or generate their own electricity. [13] In estimating stranded costs, utilities were required to use the ECOM model, [14] an estimation model earlier used in a 1998 PUC report to the Legislature. [15] Section 39.201(h) required the PUC to rerun the ECOM model using updated company-specific updates. Provision is made in Section 39.201 for a utility to recover estimated stranded costs at any time after the start of the freeze period on September 1, 1999 by issuing bonds and using a transition charge (TC) to service the bonds, [16] or by imposing a CTC. [17] However, no such charges were imposed because the Commission concluded after the updated ECOM calculations that no utility would incur stranded costs. [18] Under Section 39.262, utilities were required, after January 10, 2004, to file with the PUC a reconciliation of stranded costs and the previous estimate of stranded costs that had been used in determining rates under Section 39.201. [19] Section 39.262 further directed the PUC to conduct a true-up proceeding and enter a final order adjusting the CTC to reflect the ultimate valuation of stranded costs. [20] If, based on the proceeding, the competition transition charge is not sufficient, the commission may extend the collection period for the charge or, if necessary, increase the charge. [21] The adjusted CTC is applied to the nonbypassable delivery rates of the transmission and distribution utility. [22] In addition to adjustments for stranded costs, the PUC is directed at the true-up proceeding to make other adjustments to the nonbypassable delivery charges of the transmission and distribution utility. The parties refer to these other costs as non-stranded costs. These adjustments can result in an increase or decrease in the amount or collection period of the CTC. [23] From January 1, 2002 until January 1, 2007, affiliated retail electric providers were required to charge rates six percent below average rates that were in effect on January 1, 1999, subject to certain adjustments including a fuel factor. [24] This price is known as the price to beat. After January 1, 2002, each affiliated power-generation company is required to file a final fuel reconciliation that calculates a final fuel balance as of December 31, 2001. [25] To foster competition, utilities or their unbundled power-generation companies were required, at least 60 days before January 1, 2002, to conduct a capacity auction that sold entitlements to at least 15 percent of the utilities' generation capacity. [26] The obligation continued until the earlier of 60 months after the date customer choice was introduced or the date the Commission determined that 40 percent or more of the electric power consumed by residential and small commercial customers within the affiliated transmission and distribution utility's certificated service area before the onset of customer choice [was] provided by nonaffiliated retail electric providers. [27] Under Section 39.262(d), the Act directs the affiliated power-generation company at the true-up proceeding to reconcile and either bill or credit the transmission and distribution utility for the net sum of (1) the former integrated utility's final fuel balance, [28] and (2) a balance parties refer to as the capacity auction true-up balance or the wholesale clawback, consisting of the difference between the price of power realized at the capacity auctions and the power cost projections used in the ECOM model. [29] Section 39.262(e) directs the affiliated retail electric provider at the true-up proceeding to credit the affiliated transmission and distribution utility for any positive difference between the price to beat under Section 39.202, reduced by the nonbypassable delivery charge established under 39.201, and the prevailing market price of electricity during the same time period. [30] This credit is sometimes called the retail clawback.