- Email: [email protected]
A review of efforts to restructure Texas’ electricity market
ARTICLE IN PRESS
Energy Policy 33 (2005) 15–25
A review of efforts to restructure Texas’ electricity market$ Jay Zarnikau* Frontier Associates LLC, 4131 Spicewood Springs Rd., Suite O-3, Austin, TX 78759, USA
Abstract Comparisons suggest that Texas has been relatively successful in its efforts to introduce greater competition and customer choice into its unique electricity market (Center for Advancement of Electricity Markets, 2002). Yet, Texas has defied many of the common prescriptions in designing its market. Texas has yet to establish a nodal congestion management system that directly assigns local congestion costs to entities responsible for creating transmission congestion. A liquid power exchange or spot market is absent. Programs designed to encourage demand side responsiveness had a slow start. Market concentration remains high. Market oversight activities are poorly funded. A generation adequacy mechanism or planning reserve margin requirement remains under debate. Has Texas simply been lucky in averting any real disasters? Or are these market features less important than commonly recognized? This article reviews the restructuring initiative and reports some key lessons learned following the first twenty months under the new wholesale market structure and fifteen months of retail competition. r 2003 Elsevier Ltd. All rights reserved. Keywords: Electricity markets; Deregulation; Market restructuring
1. Introduction While other states halted initiatives to restructure their electricity markets in the wake of problems experienced in California and scandals involving Enron and other power marketers, Texas continued with an ambitious restructuring plan that was initiated in 1995 to open the wholesale electricity market and was enhanced in 1999 to prepare Texas for retail competition in 2002. This article reports the achievements and problems experienced in Texas through April 2003, thus encompassing the first twenty months of operation of the restructured wholesale market and the first fifteen months of full retail competition in the service areas of most of the State’s investor-owned electric utilities. It is hoped that the lessons learned in Texas may prove insightful to restructuring efforts elsewhere (Center for Advancement of Electricity Markets, 2002). The following section provides an historical perspective on the market structure prior to restructuring and the impetus for change. Section 3 highlights some key aspects of the restructuring initiative in Texas. Section 4 $ Dr. Parviz Adib provided invaluable comments on an earlier draft. The author is responsible for any remaining errors. *Tel.: +1-512-372-8778; fax: +1-512-372-8932. E-mail address: [email protected] (J. Zarnikau).
0301-4215/$ - see front matter r 2003 Elsevier Ltd. All rights reserved. doi:10.1016/S0301-4215(03)00193-9
reviews the performance of the market during its infant months, including the challenges encountered. The final section attempts to provide an overall assessment of the success of the restructuring effort toward meeting its policy goals at this initial stage and the lessons learned to date. The main objective is to provide a fairly comprehensive survey of market changes, issues, challenges, and successes. Consequently, the attention devoted to some of these topics is quite limited, and many of these issues may easily merit much more detailed treatment than space limitations can permit here.
2. Historical perspective and the impetus for restructuring About three-quarters of the electricity needs in the nation’s leading state in electricity generation and usage have traditionally been satisfied by utilities that were members of the Electric Reliability Council of Texas (ERCOT). ERCOT was originally established to foster reliability of service by encouraging transmission interconnections and coordinated transmission planning, and by facilitating the transfer of power among member utilities during emergencies. Traditionally, ERCOT was dominated by a few large vertically integrated investor-owned utilities, including
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
16
Texas Utilities Electric Company (now TXU), Houston Lighting and Power Company (now split into Reliant Energy and CenterPoint Energy), Central and Southwest Corp. (which later merged with American Electric Power Company), and Texas-New Mexico Power Company. Roughly 60 electric cooperatives operate in ERCOT. Nearly fifty municipal utilities systems also distribute (and in some cases, generate) electricity, including City Public Service Board of San Antonio (the nation’s second largest municipal system) and Austin Energy. Prior to restructuring in 2001–2002, retail prices charged by the vertically integrated investor-owned utilities were set by the Public Utility Commission of Texas (PUCT). Retail prices were designed so as to permit utilities a reasonable opportunity to recover their reasonable and necessary costs of business and earn a reasonable return on prudent investments. In the 1980s, the potential for competition in the generation of electricity in Texas increased. Fostered by federal legislation in the late 1970s that guaranteed a market for the electricity generated by qualifying cogeneration facilities that was in excess of on-site needs, the share of electricity produced by non-utilities in Texas grew to over 10% by the early 1990s.1 Competition in generation markets was further advanced by resource planning rules which required utilities to solicit competitive bids for resources before pursuing new power plant construction projects. Texas added 47 new power plants between 1995 and 2001, representing one-fourth of all power plants built in the nation during that period (PUCT, 2003d, undated). Nearly all of these additions to generating capacity were constructed by entities other than investor-owned utilities. Despite this increased competition, the generation sector remained fairly concentrated prior to restructuring (Zarnikau and Lam, 1998). It also became apparent that competition could be introduced into the retail sector if the existing ‘‘wires’’ infrastructure (transmission and distribution lines) could be made available to retailers on a nondiscriminatory open-access basis. Customers could then choose among a number of retail electric providers (REPs) in the same manner as they were permitted to select among long-distance telecommunications providers when the wires infrastructure of the telephone industry attained common carrier status. Beginning in the mid-1990s, states with high energy costs announced plans to restructure their electricity markets in hopes that greater competition would lead to lower costs and greater choices for consumers. These announcements followed restructuring initiatives in a number of other countries, including Norway, England
1
Zarnikau and Reilly (1996).
and Wales, Indonesia, Chile, Argentina, Spain, Australia, New Zealand, and Brazil. As in other states, industrial energy consumers provided the initial impetus for restructuring. The PUCT favored changes that would introduce greater competition into the market, particularly under the chairmanship of Pat Wood, who later became chairman of the Federal Energy Regulatory Commission (FERC, 2002). While opposed to restructuring in the mid-1990s, by 1997 the investor-owned utilities became advocates for restructuring.
3. The Texas restructuring plan and market design Senate Bill 7 was introduced by Senator David Sibley at the start of the 76th Legislative session (1999) and was revised extensively by the House State Affairs Committee chaired by Representative Steven Wolens. Under the plan, which was passed by the Texas Legislature in May 1999, customers of most of the state’s investor-owned utilities were permitted to choose among various REPs beginning in January of 2002. Pilot customer choice programs were initially scheduled to begin on June 1, 2001, although this target date slipped to July 31, 2001 due to technical delays at ERCOT. Rural electric cooperatives and municipal utility systems were permitted latitude to either participate in the plan (opt in) or decline to participate, although changes in the wholesale market would affect them regardless of their decision regarding retail choice. ERCOT was assigned responsibility to serve as an independent system operator (ISO) for most areas of Texas, with a mandate to preserve reliability, foster the final design of the market, coordinate the scheduling of wholesale transactions among market participants, coordinate the switching of customers among the REPs, facilitate the transfer of meter reads from transmission and distribution services providers (TDSPs) to the appropriate REPs, and perform financial settlements. Fig. 1 identifies the areas of the ERCOT power region offering retail competition. Vertically integrated utilities were required to separate or ‘‘unbundle’’ their operations into separate power generation company (PGC), REP, and TDSP entities before the start of customer choice. Generation and retail activities were largely deregulated, although certification requirements and various safeguards were imposed. Regulatory controls were maintained in the transmission and distribution of power, since these operations continued to be regarded as natural monopoly activities. Limitations were placed on the exchange of information and personnel between divisions or affiliates of the same entity that were involved in regulated and competitive activities.
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
17
Fig. 1. Investor owned utility service areas in Texas.
While it was initially hoped that all of the state’s investor-owned service areas would open to competition in a similar time frame, competition was later delayed in the non-ERCOT areas.2 In these areas, it was thought likely that transmission constraints would hamper competition among PGCs. The absence of an ISO or regional transmission organization (RTO), prepared to undertake the tasks necessary to permit retail competition, was of further concern. In the early 1990s, it was anticipated that recovery of stranded costs would pose a major challenge to any restructuring efforts. A number of the investor-owned utilities were involved in nuclear power plants, with generating capacity costs that were far in excess of market values. However, at the time restructuring commenced, the price of natural gas (the fuel of generating units normally operating at the margin in ERCOT and thus a key determinant of electricity market prices) was at a level that made nuclear generation appear attractive. While a variety of regulatory assets3 required attention, the treatment of 2 El Paso Electric Company was sparred competition due to its emergence from bankruptcy. However, it was originally hoped that competition would be introduced in the Entergy/Gulf States, Xcel/ Southwestern Public Service Company, and AEP/Southwestern Electric Power Company areas around the same time that retail competition was introduced into the services areas of investor-owned utilities in the ERCOT market. 3 Many of these regulatory assets were associated with costs that utilities had incurred in an earlier period. The recovery of these costs through rates was to occur in future years.
stranded costs associated with nuclear power plants failed to pose a great hurdle. In general, reform of the wholesale market preceded the introduction of customer choice at the retail level. 3.1. The wholesale market Rather than adopt a market model tested in another state or country, the policy makers and lobbyists responsible for crafting SB 7 (SB 7, Chapter 39, Subchapter A) focused on avoiding the market structural flaws that they anticipated would emerge in California and other markets. The resulting market structure is vaguely (though unintentionally) similar to the structure of the electricity market in Norway. The ERCOT wholesale market was designed to foster bilateral contracts between PGCs and REPs in order to reduce consumer exposure to hour-to-hour fluctuations in electricity prices.4 Unlike the failed California electricity market, the ERCOT ISO does not operate a centralized spot market for power (but does operate a balancing energy market with some similar attributes). Initially, ERCOT required that qualified scheduling entities (QSEs) submit ‘‘balanced schedules’’ on a dayahead basis to demonstrate that the QSE had arranged for sufficient generation resources and ancillary services to meet the expected demand it had committed to serving. Rarely are next-day forecasts of load or 4 Market rules are presented in detail in the ERCOT Protocols. For a current version, see www.ercot.com.
ARTICLE IN PRESS 18
J. Zarnikau / Energy Policy 33 (2005) 15–25
resources completely accurate. Consequently, ERCOT forecasts likely imbalances between supply and demand on an hour-ahead basis, and procures any additional generation (balancing up) or generation reductions (balancing down) that may be necessary in order to better match supply and demand on a near-real-time basis (i.e., with a notice period of between 10 and 20 min). QSEs with additional generation (beyond that necessary to meet the needs identified in its schedules) or load curtailment capability are encouraged to submit offers for balancing up energy to ERCOT. Less than 5% of ERCOT’s total generation requirements are satisfied through balancing energy. Balanced schedule requirements were relaxed on November 1, 2002, to permit load serving entities (LSEs5) and retail customers an opportunity to designate the balancing energy market as a source of a portion of the LSE’s generation portfolio. It was also hoped that relaxation of the balanced schedule requirement would encourage the establishment of private spot markets for generation. A spot market would improve price signals and transparency, encourage demand side response, and foster more efficient use of available system resources. While the private power exchanges introduced by Enron and Automated Power Exchange in 2001 failed to attract enough participation to remain commercially viable, it was hoped that relaxation of the balanced schedule requirement would facilitate renewed interest in the establishment of such private exchanges. Following price spikes in the balancing energy market in late February 2003, the ERCOT Board of Directors (ERCOT, 2003) imposed a requirement that no more than 10% of a REP’s generation requirements could be obtained from the balancing energy market without providing additional line of credits.6 ERCOT operates a variety of markets for ancillary services (i.e., operating reserves and other services necessary for the efficient and reliable operation of the power grid).7 While most markets are ERCOT-wide, others are zonal or local and designed to address regional or local transmission congestion problems. Some ancillary services are only procured by ERCOT when adverse weather, transmission congestion, or other reliability problems are anticipated (e.g., replacement capacity and out-of-merit-order energy and capacity), while others are procured on a routine daily basis (including regulation services and responsive reserves). QSEs representing PGCs make offers to provide ancillary services on a day-ahead basis. Most ancillary services markets are hourly. In general, these markets 5
LSEs encompass REPs as well as non-opt-in entities, such as municipal systems and rural electric cooperatives, that make retail sales. 6 Resolution from the ERCOT Board of Directors, March 18, 2003. 7 Chapter 6 of ERCOT Protocols at www.ercot.com.
are not very liquid, since most LSEs rely upon bilateral contracts to self-arrange most of their ancillary service needs. In the ERCOT next-day ancillary services markets, the prices of such services may be affected by such factors as the supply and demand for available power plant capacity that is not fully loaded or scheduled to provide generation, and the market power and bidding strategies of generators. ERCOT creates a bid stack or supply curve of all offers to provide ancillary services obtained from QSEs, ordering all offers from lowest to highest. Offers are accepted until the market requirement is met. All winning offers receive the market-clearing price. The QSEs associated with LSEs that are deficient in ancillary services are billed for the costs that ERCOT incurs in procuring these services on behalf of the LSE. In a move widely criticized by power generators, the PUCT placed a temporary offer cap on wholesale electricity generation prices of $1000 per MWh and $1000 per MW for ancillary services just before the new wholesale market opened on July 31, 2001.8 Despite many other safeguards, the state’s regulators remained uneasy about turning over wholesale electricity prices entirely over to the forces of competition in a new and untested market structure. The management of transmission congestion has proven to be a key challenge in all restructuring efforts. Congestion arises when the schedules submitted by QSEs imply power flows that would exceed transmission line limits, resulting in the re-dispatch of generation units. Congestion costs represent the increased supply costs attributable to the transmission constraints. Initially, any congestion costs were simply uplifted to the market and assigned to QSEs in proportion to their load of the LSEs they represent. As congestion costs rose and gaming opportunities became apparent, this was replaced, effective on February 15, 2002, with a zonal congestion management system that better assigns congestion costs to the entities responsible for creating the congestion (at least at a zonal or regional level). ERCOT’s zonal approach to congestion management contrasts with other competitive markets in the US and the FERC’s proposed Standard Market Design (SMD). However, zonal or flowgate approaches are popular in a number of countries outside of North America. Initially three, and later four, congestion zones were established to ration the use of the transmission system during periods of binding transmission capacity constraints. Congestion between zones is managed through the deployment of balancing energy and other means. QSEs pay for congestion costs based on the QSE’s impact on commercially significant transmission constraints (CSCs) and the constraint’s shadow price or marginal 8 Typically, wholesale electricity prices range from the high 20s to mid 30s ($/MWh).
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
cost. Transmission congestion rights (TCRs) are auctioned to the highest bidder for monthly or annual periods and provide suppliers with a means of hedging their inter-zonal congestion cost risk (ERCOT, 2001). Congestion within each zone is managed through ERCOT’s use of out-of-merit-order (OOM) instructions. Under an OOM instruction, a resource (i.e., a power plant or an interruptible load) that is not already scheduled for deployment may be deployed by ERCOT to address a transmission congestion problem. OOM costs are uplifted to all market participants, i.e., these costs are not yet directly assigned to the entities responsible for imposing the costs. In order to dilute market power, no generator is permitted to control over 20% of the installed generating capacity in ERCOT. Further, the larger utilities were required to auction off ‘‘entitlements’’ to a share of the generating capacity for which they retained ownership. Each PGC associated with a utility with at least 400 MW of Texas-jurisdictional installed capacity must sell at auction entitlements to at least 15% of that capacity. In order to satisfy social and environmental goals and constrain demand growth, 10% of the growth in electricity demand must be met through energy efficiency programs that are administered by the TDSPs. Also, a renewable energy portfolio standard was imposed to increase the State’s renewable energy generating capacity by 2000 MW by 2009. 3.2. Retail market design Retail price caps were imposed on the prices charged by REPs affiliated with the incumbent utility (the ‘‘AREPs’’). AREPs were required to reduce the electricity prices charged to residential and small commercial customers9 by 6%, adjusted for fuel rate revisions and certain stipulated base-rate reductions not yet in effect by January 1, 1999. The resulting price provides a benchmark price-to-beat (PTB) for potential competitors. This PTB remains in effect for five years. However, the incumbent utility’s REP can begin charging rates other than the PTB after 36 months or when the AREP loses at least 40% of its residential and small commercial customer load to competitors. After either of these events occurs, the PTB establishes only a ceiling, and the AREP may also offer lower prices. Larger energy consumers in Texas received no price cap protection. Adjustments for the fuel portion of the PTB are limited to two changes per year, unless an AREP is unable to maintain its financial integrity under the prevailing PTB rates or if transmission and distribution costs significantly change. 9 In Texas, the PTB applies to customers with a billing demand below 1 MW.
19
The PUCT designated ‘‘providers of last resort’’ (POLRs) to ensure that all Texans received electric service in the event that their REP went out of business or pulled out of the market. Initially, customers that failed to pay their electric bills were also dropped to the POLR, but later the POLR rules were redesigned so that such customers were dropped to the AREP. Under the current POLR rules, a customer whose electricity contract with a competitive REP (CR) expires is sent to the POLR if the customer fails to renew the contract or exercise any other electricity choice. The energy consumption and billing demand of energy consumers with a peak demand of over 1 MW is measured with interval data recorders. Statistical load profiles were developed for smaller customers. The assumed profile for each of the profiled customers is estimated on a day-ahead basis using a spreadsheet which predicts the profile based on forecasted weather, day type, and other factors. In some respects, the ERCOT organization has assumed a greater role in retail market operations than have ISOs in other restructured markets. The switching of customers from one REP (e.g., the AREP) to another REP (e.g., a CR) requires the use of ERCOT’s customer databases and systems. ERCOT serves as the Central Registration Agent. Customer switches require completion of a large number of electronic transactions via the Texas Standard Electronic Transactions (Texas SET) system. A switch request is first sent by a REP who has signed up a new customer to ERCOT. ERCOT confirms the apparent validity of the switch request and forwards it to the appropriate TDSP. The TDSP checks the switch request and provides a confirmation to ERCOT along with information pertaining to the next meter read date. ERCOT then notifies the REP gaining the customer and the REP losing the account. Meter reads taken by the TDSPs are sent to ERCOT, which then forwards billing data to the appropriate REP. The ownership of meters will become a competitive service on January 1, 2004 for commercial and industrial customers, and will become a competitive service for residential consumers on a later date. REPs are responsible for collecting from their customers various delivery charges to compensate the owners of the transmission and distribution system for its use, as well as contributions to the System Benefit Fund charges, nuclear decommissioning costs, any transition cost or stranded cost charges, and other charges approved by the PUCT. The Systems Benefit Fund was established to fund programs to assist low-income families, provide customer education regarding customer choice, and compensate local school districts for any tax losses resulting from restructuring. In hopes of encouraging competition for residential energy consumers, REPs that serve more that 400 MW
ARTICLE IN PRESS 20
J. Zarnikau / Energy Policy 33 (2005) 15–25
of load and fail to make at least 5% of their sales to residential customers face a penalty.
Balancing Energy Prices Houston - Week of February 23, 2003 vs Average Price for Previous 12 Months
$1,000
4. Market performance
$ per MWh
This section reviews the performance of the Texas market since restructuring began and progress toward meeting the goals of lower electricity prices and expanded choices, while preserving the historically high levels of customer service. The performance of the wholesale market is first reviewed, followed by a review of retail market performance and institutional impacts.
12-Month Average $31.32
$800
$600
$400
$200
4.1. Wholesale market performance The restructuring of the wholesale market is generally regarded as a success. Reliability has been maintained, and the problems that plagued the California market have been largely avoided. As natural gas prices increased following restructuring, the PTB was raised accordingly, thus preventing the type of price squeeze between wholesale costs and retail prices that financially damaged the retail operations of the incumbent investor-owned utilities in California. Volatility in wholesale market prices have harmed REPs that were not well hedged (forcing one into bankruptcy), but have not cause the widespread damage that resulted from price spikes in California, where the majority of retail power requirements were procured through a centralized power exchange. Part of the relative success of the wholesale market restructuring is a direct result of the high reserve margins that Texas enjoyed at the start of restructuring. Due to the surplus generating capacity, prices remained generally low. This is fortunate, since appropriate generation adequacy mechanisms were still under debate in early 2003. Delays were encountered in implementing the systems necessary to consolidate ten utility control centers into a single control center. Numerous changes in market procedures were required as problems became apparent. Several PGCs or power marketers allegedly discovered a market flaw that permitted them to reap profits by over-scheduling generation in August 2001, thus prompting inquiries from the PUCT staff (PUCT, 2001a, b). Four of the six QSEs accused of this practice—American Electric Power Company, Mirant, Reliant, and TXU Electric—eventually agreed to return over $10 million to the market. A tentative settlement has also been reached with Enron Power Marketing. Three significant price spikes in ERCOT’s wholesale markets have occurred since the opening of the market. On the first day of the restructured market, July 31, 2001, prices in the markets for non-spinning reserves and responsive reserves ancillary services shot up to the
$0
2/23/0
2/24/03
2/25/03
2/26/03
2/27/03
2/28/03
Fig. 2. Balancing energy prices, Houston—Week of February 23, 2003.
price cap of $1000 per MW when the largest power producer, TXU Electric, failed to submit its power schedules and offers into ERCOT by the market’s deadline. The two later price spikes were largely the result of poor weather forecasts. The price caps were reached in late April 2002 during a week of unseasonally warm weather and delays in introducing interruptible loads into the new wholesale market as a potential resource. In late February 2003, colder than anticipated weather struck North and Central Texas and gas curtailments affected some generating units while a number of large generating units were down for maintenance. This propelled balancing energy and responsive reserve prices to their capped values (Saathoff, 2003). Balancing energy market prices set during this week are depicted in Fig. 2. ‘‘Hockey stick bidding’’10 by generation suppliers contributed to the price spike (PUCT, 2003a). The legislative mandate promoting renewable energy projects, coupled with uncertainty regarding the possible expiration of the federal production tax credit for renewable energy caused a boom in the construction of wind-to-energy projects. By late 2002, roughly 1000 MW of renewable energy capacity had been completed, greatly exceeding the year-end goal of 400 MW. Yet the construction of renewable generating capacity outpaced the construction of the necessary transmission capability, highlighting the absence of coordination between generation siting and transmission 10 This refers to the practice of submitting a small portion of a bidder’s resource fleet to the market at a very high price, in hopes that the small-high price increment will set the clearing price for the whole market.
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
11
Synchronous Interconnection Committee (1999).
Price of Responsive Reserves and Non-Spinning Reserves April 28, 2002 through May 1, 2002 $1,000
$800
$ per MW
planning and an absence of proper pricing signals to guide investment siting decisions. In the McCamey area of West Texas, 758 MW of wind-to-energy capacity was constructed in an area with a transmission export capability of only 400 MW. Some doubt remains whether ERCOT’s wholesale market will prove workably competitive in the longer run. Simple measures of market concentration using Hirfindahl-Hirschman Index (HHI) calculations suggest that the ERCOT market is either highly concentrated or moderately concentrated (Zarnikau and Lam, 1998). The staff of the PUCT has observed that ERCOT is probably the most concentrated of the deregulated wholesale markets in the US (PUCT, 2003b). The PUCT staff has also examined market concentration in sub-markets within ERCOT.11 Illiquid markets and oligopolistic market power tend to yield volatile prices. ERCOT has been slow to introduce demand-side response programs and to introduce demand-side resources into ancillary services markets. Interruptible customers are slowly being introduced into ancillary services markets to permit their interruptibility to compete head-to-head with an offer from a power plant to provide generation or an operating reserve. In some of ERCOT’s markets, a reduction in demand or the ability to interrupt customer demand (a ‘‘load’’) may be just as valuable (and in many cases, more valuable) than an increase in generation supply or the availability of additional power plant capacity. In mid-May 2002, interruptible and curtailable loads were permitted to participate in the market for responsive reserves as a resource on a limited basis, and interruptible loads were introduced into the markets for non-spinning reserves and replacement capacity in October of 2002. By March 2003, nearly 1000 MW of interruptible loads had been registered to participate in ancillary services markets. Yet the amount of load that may be interrupted or curtailed remains far below pre-restructuring levels of roughly 3500 MW (if all loads served under interruptible service tariffs, group load curtailment programs, direct load control, and energy storage devices were counted). During the first year of wholesale market operations, price reversals occurred in many intervals. Price reversals occur when the market price for an inferior service (e.g., non-spinning reserves) exceed the market price in a superior service (e.g., responsive reserves). An example is shown in Fig. 3 for the April 2002 price spike. This problem is being addressed through the introduction of a simultaneous procurement auction process which will optimize procurement of ancillary services by assigning resources offered to multiple markets to the market where they should have the greatest value. Texas policymakers recognize the importance of a strong transmission system to minimize transmission
21
$600
$400
$200
NonSpinning Reserve
$0
4/28/02
4/29/02
4/30/02
5/01/02
Responsive Reserve
Fig. 3. Price of responsive reserves and non-spinning reserves: April 28, 2002–May 1, 2002.
congestion, and a construction boom in transmission lines is underway. Nonetheless, transmission constraints within the ERCOT market have proven to be a greater problem than originally appreciated, particularly in the Dallas-Fort Worth area, the Rio Grande Valley, Laredo, and West Texas. While most of the new markets for generation and ancillary services were designed to be ERCOT-wide, moving power from certain power plants to energy consumers has proven to be a formidable task. The cost of paying certain generators to produce power just to relieve transmission congestion quickly exceeded early estimates.12 Wind power generators in West Texas keep overloading the only transmission line from their sites to the rest of the market. Congestion costs totaled about $220 million between July 31, 2001 and April 1, 2003. There is growing dissatisfaction with the present approach to congestion management. While congestion between regions or zones is now being managed in a reasonable manner, the costs associated with managing local congestion costs are still being uplifted. Some market participants suggest adopting the method used in PJM; that is, locational marginal pricing (LMP). The PUCT has expressed interest in moving toward some type of nodal pricing which would better assign all congestion costs to the market participants responsible for creating congestion. Some power from cogeneration facilities has yet to find a home under the new market structure. Under federal law, utilities are obligated to purchase excess cogenerated power from qualifying facilities (QFs) at a price no higher than the utility’s avoided cost. However, under the new market structure, the regulated utility is a TDSP that has no need for generation and has no 12 In California, Duke Power and Enron received payments from all market participants to relieve transmission congestion that they allegedly had artificially created (the so-called ‘‘dec game’’). Concerns have been expressed that similar behavior could occur in Texas.
ARTICLE IN PRESS 22
J. Zarnikau / Energy Policy 33 (2005) 15–25
avoidable generating capacity and energy costs. Thus, the PUCT and FERC have reached an impasse over how to treat cogeneration from QFs in the new market. Historically, the PUCT could ensure a minimum level of planning reserves by requiring each of the larger vertically integrated utilities to maintain 15% reserve margins. It has proven difficult to enforce generation adequacy standards under the new market structure. Various proposals are still being considered. However, there may not be an urgency to finalize a plan given existing significant excess capacity. ERCOT’s reserve margins are projected to remain above 30% until 2008. Overall, wholesale market operations have proceeded fairly well. Reliability has been maintained at acceptable standards and competition has increased. The wholesale market design is certainly not perfect—gaming opportunities were quickly discovered, the congestion management system fails to appropriately assign costs in an economically efficient manner, generation siting decisions have created market problems, and there have been setbacks in the areas of generation and transmission planning. Yet, ERCOT’s wholesale market prior to restructuring had its own set of problems. Market participants remain generally optimistic that the remaining transitional problems can be resolved. However, further movement toward a nodal system of congestion management could pose a major challenge. 4.2. Retail market performance ERCOT has had a great deal of difficulty in performing many of the customer service and billing activities that the vertically integrated utilities had performed so well and had been largely taken for granted. Some of the tasks that proved formidable to ERCOT included assigning account numbers (‘‘ESI IDs’’) to new premises, customer switching, collection and distribution of billing data, and disconnection and re-connection of service (‘‘Move-In, Move-Out’’). Customer switching problems have been traced to many causes, including software failures, vague language in ERCOT’s Protocols regarding when a TDSP can reject a switch request, higher-than-anticipated traffic on the ERCOT portal (which provides necessary information to REPs about specific customers), errors in ERCOT’s ZIP code database (which was used as a check to verify the validity of information pertaining to a customer), delays in creating ESI IDs for new buildings and premises, and typographic errors in switch requests. In March 2002, there were about 8000 pending switch requests that seemed to be ‘‘stuck’’ in the switching process.13
Most of the delays appeared to be associated with situations in which ERCOT’s records did not match those of the TDSPs.14 REPs were not certain which customers they had, and for which customers they were responsible for procuring and scheduling generation resources. Through the Market Metrics project, samples of transactions were followed through the switching process, in order to pinpoint problems. It was found that only about half of switching transactions were actually getting completed within a twelve day time frame during Spring of 2002, and of the transactions that were successfully completed, only about one-half were completed within the five-day timeline target established in ERCOT’s Protocols. Many of the switch requests were rejected by the TDSPs due to bad REP Duns numbers (identifiers assigned to REPs), bad dates for the switch request,15 problems with the computer systems at Oncor (a division of TXU and the largest TDSP), duplicate transactions, and indications that the meter had been removed from the customer premise. Because of the delays encountered in processing switch requests, TDSPs were eventually required to backdate valid switch requests in cases where the request should have gone through, but failed to be completed due to a problem with ERCOT’s systems. Delays in processing switch requests caused tremendous problems. Because REPs were not sure which customers they really had, they were uncertain of how much load they were required to schedule power and arrange ancillary services for. Thus, on many occasions, no REPs or multiple REPs were scheduling power for the same customer. In early 2002, a large number of customers were receiving electricity, but had not selected a REP nor had otherwise been assigned to a REP. American Electric Power Company had over 10,000 customers in this group in March 2002. Many of these customers received free electricity. In some cases, customers called the TDSP directly (rather than a REP) to request service. Because REPs were having difficulty starting service for new customers, some of the TDSPs (sympathetically) initiated service for the new customer even without a request from a REP. In other cases, new customers received service that was initiated for a previous tenant or homeowner. Because of delays in getting new service initiated, the PUCT asked utilities to cease disconnecting service when a customer requested a disconnection. Thus, electricity continued to be available in dwellings between tenants. The new tenant was supposed to select a REP and the REP was supposed to notify ERCOT that a new tenant was to be billed for electricity. 14
13
The source of this information is data presented at Retail Market Subcommittee (RMS) meetings during the Spring of 2002.
RMS meeting during the Spring of 2002. For example, CenterPoint Energy received one switch request dated 1924. 15
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
However, there was no incentive for a new tenant to do so. If the tenant took no action, the tenant would continue to receive free electricity. Consequently, anyone that wanted free electricity could simply request service disconnection (which wouldn’t happen), and would no longer be billed for the continuing electric service. Billboards started sprouting up around the State reading: ‘‘Call this number and find out how to get free electricity.’’ Because of the problems in collecting meter read data from the TDSPs and distributing it to the REPs and the uncertainty over who actually had various customers, many customers did not receive electric bills for several months in 2002. Despite the problems associated with customers switching and billing, retail competition clearly provided noticeable benefits. New choices were introduced by new retailers, who included independent REPs (e.g., Green Mountain Energy), affiliates of utilities that previously had no operations in ERCOT (e.g., Sempra, Xcel Energy Retail Services, Entergy Solutions, Strategic Energy, and Constellation), and independent power producers or oil and gas company affiliates that entered the retail market (e.g., Dynegy, Calpine, Tenaska, Tractabel, and Coral), and new firms (e.g., Utility Choice, GEXA, and Texas Commercial Energy). In March 2003, 30 REPs were certified to provide electricity at the retail level to commercial customers, while 11 were certified to serve residential customers (www.powertochoose.org\yourchoice\yourchoiceframe. html). Much of the greatest competition was simply from AREPs competing outside of their traditional service areas (e.g., TXU Energy Solutions, Reliant Energy Solutions, and First Choice Power competing in each other’s former retail service areas). About 7% of residential customers affected by retail competition switched to a different REP by the end of 2002 (PUCT, 2003e, undated). With no price-to-beat protections and often with greater opportunities for savings, about 20% of industrial (primary and transmission voltage) customers accounting for about 60% of the total energy consumption in that group had switched by the end of 2002 (PUCT, 2003a). Clearly, many energy consumers benefited from lower rates. The PUCT estimates that retail customers saved over $1.5 billion in 2002 relative to regulated rates that were in effect in 2001 (PUCT, 2003c). As in other restructured markets, large industrial energy consumers have fared relatively well under restructuring. Commercial and industrial consumers that switched in mid-2002 could expect savings in the 20% range. While residential energy consumers have enjoyed a 6% decrease in the base rates, relatively few have switched. It remains difficult to determine the extent to which smaller customers have benefited from retail competition.
23
By the end of 2002, over 130 load aggregators had registered with the PUCT (2003c, p. 8). Load aggregation has proven effective, but not in the manner predicted. True aggregation (where the load diversity benefits of serving large groups of customers is recognized) is difficult in Texas, for a number of reasons. ERCOT settles each QSE’s ESI IDs separately. If customers under 1 MW without IDRs fall within the same load factor group, their load pattern is assumed to be the same as all other customers in that group. Thus, the load profiling system in ERCOT fails to recognize any load diversity among different customers within the same load factor category, and the true diversity benefits associated with serving a group’s generation needs are difficult to recognize. The transmission and distribution costs associated with serving each commercial customer are billed to the REP based on the customer’s billing demand. Since this billing demand is usually based on the customer’s non-coincident peak, here again load diversity is not taken into consideration. Consequently, thus, true aggregation is difficult unless all members of the aggregation group have IDRs. Yet, load aggregators have been able to deliver significant savings to their clients by improving their client’s bargaining power and negotiating strength. Nonetheless, certain types of group energy procurement programs are working fairly well and customers are benefiting through greater bargaining power and the consulting services available through the programs. In a market where natural gas prices have a considerable impact on electricity retail prices, electricity prices will be volatile. The retail prices quoted by REPs may be honored for periods as short as 24 h. Locking-in prices at an appropriate time has posed a challenge for retail customers. The POLR feature of the market has worked poorly. The POLR was originally designed as a default provider for customers with poor bill payment histories and for customers of REPs that exit the market. Understandably, the concept of charging the same electric rates to those two classes of customers with very different characteristics has not worked. When New Power Company (a former affiliate of Enron) exited from the market and when Texas Commercial Energy shed most of its customers as it filed for Chapter 11 Bankruptcy protection, most customers of those REPs were sent to various AREPs (at lower prices), instead of being directed to the POLR. Very few REPs have expressed any interest in becoming a POLR, given the regulatory constraints on POLR’s rates and the REP’s lack of control over its customer base. Customer service has undoubtedly declined since the introduction of retail customer choice. Confusion continues over which entity to contact in the event of an outage. The marketing tactics of certain REPs have drawn fire. The billing and switching problems have
ARTICLE IN PRESS 24
J. Zarnikau / Energy Policy 33 (2005) 15–25
raised concerns. Some TDSPs have been unable to furnish billing history data in a timely manner, thus hampering retail marketing activities. One of the surprising outcomes from restructuring has been the lack of innovative rate offerings on the part of CRs. Under regulation, the utilities offered a vast array of tariff options for their customers, including interruptible service with different notice periods, curtailment programs, time-of-use pricing, and real-time pricing. While some of the AREPs have custom designed new services to meet specific customer needs, most AREPs have struggled to design simple firm service contracts. So far, the new imaginative product and service offerings that were supposed to emerge from the competitive retail market have failed to materialize. The unbundling process created a variety of problems as well. The PUCT sought to restrict the TDSP’s contact with ultimate retail customers and prevent the TDSPs from providing any services which could potentially be provided by firms in competitive generation or retail markets. However, the REPs and PGCs have shown little interest in providing security lighting, energy efficiency services, transformers on customer premises, and similar services. Street lighting seemed to get lost in the shuffle. There has been confusion regarding whether analysis and information based on metered data (e.g., pulse outputs) is a competitive or regulated service. Consequently, there have been gaps in services that energy consumers traditionally expected in Texas. Many REPs clearly underestimated the challenges involved in earning a profit in a competitive retail electricity market. The traditional utility suppliers had historically enjoyed favorable customer satisfaction ratings. The CRs had little name recognition in Texas prior to restructuring. The CRs found it difficult to compete with the AREPs on the basis of price, given the AREP’s access to relatively low-cost generation from nuclear, coal, and lignite plants. For a short period of time, Texas Commercial Energy was able to compete on the basis of price, but its absence of any hedging strategy eventually caught up with it and sent the upstart into bankruptcy. A number of REPs have already terminated efforts to recruit additional customers after failing to achieve profit targets or after running into credit problems, including AES (which later sold its retail operations to Constellation), and Dynegy. American Electric Power Company decided to transition out of the retail market before retail choice was even initiated— most of its remaining retail customers are being switched to Centrica. 4.3. Institutional impacts An objective of restructuring was to reduce the degree of government control over certain activities. Yet, the shift in power from the PUCT to ERCOT and the
market in general has been greater than planned, in some respects. In the early 1990s, ERCOT had a staff of three people with responsibility for coordinating meetings among the utility members of the reliability council and filing reports with the National Electric Reliability Council and various government agencies. By April 2003, ERCOT had grown into a fairly large organization with over 125 members (e.g., TDSPs, LSEs, PGCs, and industrial energy consumers) and a staff of over 300 budgeted to reach to 400 by the end of 2003. As might be expected when an organization grows as fast as ERCOT, the organization has faced a number of problems related to its leadership, staffing, and direction. In early 2002, while ERCOT was experiencing its worst customer switching and billing problems and complaining about budget limitations, the organization was funding a minor league baseball all-star game, a minor league ice hockey team, and a lavish Christmas party for its staff. Members of the Texas Legislature have questioned the competence of the organization’s leadership. The stakeholder process that has been used to develop ERCOT’s Protocols and Operating Guides and review the work performed by consultants has worked fairly well. Yet safeguards may be necessary to ensure that the stakeholder process does not become a cartel, with a few powerful market participants with significantly greater resources exercising undue control over the process and outcomes. The PUCT has clearly seen its power and authority diminish. While ERCOT theoretically reports to the PUCT, the Commission’s regulatory control over the market has greatly diminished. Historically, the Commission could impose financial penalties on a regulated utility that failed to comply with Commission orders. But, if ERCOT stakeholders or the ERCOT staff do not want to follow a Commission order, there is little the Commission can now do. The PUCT cannot effectively impose a financial penalty on ‘‘the market.’’ While most other markets in North America have established market monitoring organizations within the ISO or regional transmission organization, ERCOT’s market monitoring function resides at the PUCT. The PUCT established a new Market Oversight Division (MOD) in August 2000 with responsibility for market monitoring activities within ERCOT Market. In addition, a new Section, Retail Market Oversight, was created in the Electric Division to address retail market monitoring issues. While assigning market monitoring to the PUCT presents some advantages (e.g., providing a more independent check on market activities and ERCOT’s implementation of market rules combined with enforcement authority), the PUCT’s funding and resource constraints have posed a challenge. The need for additional resources to support PUCT market
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
monitoring functions are recognized by the Texas Legislature and a decision has been made to provide additional funding through the System Benefit Fund. MOD has selected a consulting firm to enhance its market monitoring capabilities.
5. Overall assessment It is far too early to determine whether Texas has succeeded in designing a competitive electricity market that will result in lower energy costs and greater choices for consumers without sacrificing reliability and customer service. Even if ERCOT continues to out-perform other restructured markets in North America, it may be difficult to determine whether its success is due to its market design or simply the setting and the circumstances in which it has developed. As in other restructured markets, the beneficiaries of retail competition have been industrial and commercial energy consumers. They have realized significant energy cost savings by switching suppliers. The number of residential consumers that have switched retail providers is quite small (yet higher than in many other markets offering customer choice). Indeed, new retail providers have been attracted to the ERCOT market. Yet, most are targeting industrial and commercial customers. Some retailers have left the market, due to credit problems, failure to meet profitability targets, or bankruptcies. Aside from a couple of ‘‘green power’’ offerings, we have not seen the innovative and creative pricing and services that competition promised. Many of ERCOT’s biggest problems resulted when it assumed the role of Central Registration Agent. The ERCOT organization did not have adequate resources, information systems, and expertise to process switch requests, assign ESI ID account numbers, get service turned on in new buildings, and funnel billing data from the TDSPs to the appropriate retail organizations. This resulted in long delays and errors in switching and billing activities, and ultimately, deteriorated customer satisfaction. ERCOT has faced a lot of problems and constantly modified its systems to address these problems. ERCOT and Market Participants have shown a great willingness to explore ways to improve ERCOT systems and enhance the operation of its competitive electricity system. ERCOT has avoided the market meltdown suffered in California. But it is debatable whether these problems have been avoided due to a better market design (e.g., greater reliance on bilateral contracts to hedge wholesale price risks and price-to-beat rates that can be adjusted for fuel market changes), a better market climate (e.g., higher generation reserve margins and a stronger
25
transmission system), or other factors (e.g., greater scrutiny following California’s problems, an absence of federal regulatory jurisdiction, or a different set of market participants). Most likely, it is a combination of many factors. A key lesson learned was that even after the market opened to wholesale competition and retail customer choice, market design activities continued. Some very major changes have been implemented in ERCOT after market open, including changes to balanced schedule requirements, major revisions to the POLR rules, new procedures to assign resources to ancillary services markets, and changes to congestion management. Further sweeping changes to congestion management may be pursued in the future. While these continuous changes create major challenges, they clearly demonstrate that ERCOT and its Market Participants have shown high willingness to explore ways to improve ERCOT’s systems and enhance the operation of its competitive electricity system. Despite the work completed during these initial months, there clearly remain a number of challenges ahead for the establishment of an efficient electricity market in Texas.
References Center for Advancement of Electricity Markets, 2002. Retail Energy Deregulation Index. ERCOT, 2001. A guide to how the Electric Reliability Council of Texas (ERCOT) facilitates the competitive power market, Version 1.2. ERCOT, 2003. Protocols, www.ercot.com. Federal Energy Regulatory Commission, 2002. Docket No. RM01-12000: Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design. PUCT, 2001a. Power to Choose: FAQ, www.powertochoose.org/ whatschanging/safetyframe.html. PUCT, 2001b. Docket No. 25755: PUC investigation into overscheduling in ERCOT in August 2001. PUCT, 2003a. Market oversight division, analysis of balancing energy price spikes during the extreme weather event of February 24–26. PUCT, 2003b. Market oversight division, comparison of market designs. Project No. 26376: Rulemaking Proceeding on Wholesale Market Design Issues in the Electric Reliability Council of Texas. PUCT, 2003c. Scope of competition in electric markets in Texas. Report to the 78th Texas Legislature. PUCT, 2003d. Electricity choice: Texas is different from California, Undated. PUCT, 2003e. February 2003 Report card on competition, undated. Saathoff, K., 2003. ERCOT Staff, Operations Update, Presentation to ERCOT’s Technical Advisory Committee. Synchronous Interconnection Committee (1999). Report to the 76th Texas Legislature: Feasibility Investigation for AC Interconnection between ERCOT and SPP/SERC. Zarnikau, J., Lam, A., 1998. Market Power and Market Concentration in Texas (ERCOT). Electricity Journal. Zarnikau, J., Reilly, R., 1996. The evolution of the cogeneration market in Texas. Energy Policy.
Energy Policy 33 (2005) 15–25
A review of efforts to restructure Texas’ electricity market$ Jay Zarnikau* Frontier Associates LLC, 4131 Spicewood Springs Rd., Suite O-3, Austin, TX 78759, USA
Abstract Comparisons suggest that Texas has been relatively successful in its efforts to introduce greater competition and customer choice into its unique electricity market (Center for Advancement of Electricity Markets, 2002). Yet, Texas has defied many of the common prescriptions in designing its market. Texas has yet to establish a nodal congestion management system that directly assigns local congestion costs to entities responsible for creating transmission congestion. A liquid power exchange or spot market is absent. Programs designed to encourage demand side responsiveness had a slow start. Market concentration remains high. Market oversight activities are poorly funded. A generation adequacy mechanism or planning reserve margin requirement remains under debate. Has Texas simply been lucky in averting any real disasters? Or are these market features less important than commonly recognized? This article reviews the restructuring initiative and reports some key lessons learned following the first twenty months under the new wholesale market structure and fifteen months of retail competition. r 2003 Elsevier Ltd. All rights reserved. Keywords: Electricity markets; Deregulation; Market restructuring
1. Introduction While other states halted initiatives to restructure their electricity markets in the wake of problems experienced in California and scandals involving Enron and other power marketers, Texas continued with an ambitious restructuring plan that was initiated in 1995 to open the wholesale electricity market and was enhanced in 1999 to prepare Texas for retail competition in 2002. This article reports the achievements and problems experienced in Texas through April 2003, thus encompassing the first twenty months of operation of the restructured wholesale market and the first fifteen months of full retail competition in the service areas of most of the State’s investor-owned electric utilities. It is hoped that the lessons learned in Texas may prove insightful to restructuring efforts elsewhere (Center for Advancement of Electricity Markets, 2002). The following section provides an historical perspective on the market structure prior to restructuring and the impetus for change. Section 3 highlights some key aspects of the restructuring initiative in Texas. Section 4 $ Dr. Parviz Adib provided invaluable comments on an earlier draft. The author is responsible for any remaining errors. *Tel.: +1-512-372-8778; fax: +1-512-372-8932. E-mail address: [email protected] (J. Zarnikau).
0301-4215/$ - see front matter r 2003 Elsevier Ltd. All rights reserved. doi:10.1016/S0301-4215(03)00193-9
reviews the performance of the market during its infant months, including the challenges encountered. The final section attempts to provide an overall assessment of the success of the restructuring effort toward meeting its policy goals at this initial stage and the lessons learned to date. The main objective is to provide a fairly comprehensive survey of market changes, issues, challenges, and successes. Consequently, the attention devoted to some of these topics is quite limited, and many of these issues may easily merit much more detailed treatment than space limitations can permit here.
2. Historical perspective and the impetus for restructuring About three-quarters of the electricity needs in the nation’s leading state in electricity generation and usage have traditionally been satisfied by utilities that were members of the Electric Reliability Council of Texas (ERCOT). ERCOT was originally established to foster reliability of service by encouraging transmission interconnections and coordinated transmission planning, and by facilitating the transfer of power among member utilities during emergencies. Traditionally, ERCOT was dominated by a few large vertically integrated investor-owned utilities, including
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
16
Texas Utilities Electric Company (now TXU), Houston Lighting and Power Company (now split into Reliant Energy and CenterPoint Energy), Central and Southwest Corp. (which later merged with American Electric Power Company), and Texas-New Mexico Power Company. Roughly 60 electric cooperatives operate in ERCOT. Nearly fifty municipal utilities systems also distribute (and in some cases, generate) electricity, including City Public Service Board of San Antonio (the nation’s second largest municipal system) and Austin Energy. Prior to restructuring in 2001–2002, retail prices charged by the vertically integrated investor-owned utilities were set by the Public Utility Commission of Texas (PUCT). Retail prices were designed so as to permit utilities a reasonable opportunity to recover their reasonable and necessary costs of business and earn a reasonable return on prudent investments. In the 1980s, the potential for competition in the generation of electricity in Texas increased. Fostered by federal legislation in the late 1970s that guaranteed a market for the electricity generated by qualifying cogeneration facilities that was in excess of on-site needs, the share of electricity produced by non-utilities in Texas grew to over 10% by the early 1990s.1 Competition in generation markets was further advanced by resource planning rules which required utilities to solicit competitive bids for resources before pursuing new power plant construction projects. Texas added 47 new power plants between 1995 and 2001, representing one-fourth of all power plants built in the nation during that period (PUCT, 2003d, undated). Nearly all of these additions to generating capacity were constructed by entities other than investor-owned utilities. Despite this increased competition, the generation sector remained fairly concentrated prior to restructuring (Zarnikau and Lam, 1998). It also became apparent that competition could be introduced into the retail sector if the existing ‘‘wires’’ infrastructure (transmission and distribution lines) could be made available to retailers on a nondiscriminatory open-access basis. Customers could then choose among a number of retail electric providers (REPs) in the same manner as they were permitted to select among long-distance telecommunications providers when the wires infrastructure of the telephone industry attained common carrier status. Beginning in the mid-1990s, states with high energy costs announced plans to restructure their electricity markets in hopes that greater competition would lead to lower costs and greater choices for consumers. These announcements followed restructuring initiatives in a number of other countries, including Norway, England
1
Zarnikau and Reilly (1996).
and Wales, Indonesia, Chile, Argentina, Spain, Australia, New Zealand, and Brazil. As in other states, industrial energy consumers provided the initial impetus for restructuring. The PUCT favored changes that would introduce greater competition into the market, particularly under the chairmanship of Pat Wood, who later became chairman of the Federal Energy Regulatory Commission (FERC, 2002). While opposed to restructuring in the mid-1990s, by 1997 the investor-owned utilities became advocates for restructuring.
3. The Texas restructuring plan and market design Senate Bill 7 was introduced by Senator David Sibley at the start of the 76th Legislative session (1999) and was revised extensively by the House State Affairs Committee chaired by Representative Steven Wolens. Under the plan, which was passed by the Texas Legislature in May 1999, customers of most of the state’s investor-owned utilities were permitted to choose among various REPs beginning in January of 2002. Pilot customer choice programs were initially scheduled to begin on June 1, 2001, although this target date slipped to July 31, 2001 due to technical delays at ERCOT. Rural electric cooperatives and municipal utility systems were permitted latitude to either participate in the plan (opt in) or decline to participate, although changes in the wholesale market would affect them regardless of their decision regarding retail choice. ERCOT was assigned responsibility to serve as an independent system operator (ISO) for most areas of Texas, with a mandate to preserve reliability, foster the final design of the market, coordinate the scheduling of wholesale transactions among market participants, coordinate the switching of customers among the REPs, facilitate the transfer of meter reads from transmission and distribution services providers (TDSPs) to the appropriate REPs, and perform financial settlements. Fig. 1 identifies the areas of the ERCOT power region offering retail competition. Vertically integrated utilities were required to separate or ‘‘unbundle’’ their operations into separate power generation company (PGC), REP, and TDSP entities before the start of customer choice. Generation and retail activities were largely deregulated, although certification requirements and various safeguards were imposed. Regulatory controls were maintained in the transmission and distribution of power, since these operations continued to be regarded as natural monopoly activities. Limitations were placed on the exchange of information and personnel between divisions or affiliates of the same entity that were involved in regulated and competitive activities.
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
17
Fig. 1. Investor owned utility service areas in Texas.
While it was initially hoped that all of the state’s investor-owned service areas would open to competition in a similar time frame, competition was later delayed in the non-ERCOT areas.2 In these areas, it was thought likely that transmission constraints would hamper competition among PGCs. The absence of an ISO or regional transmission organization (RTO), prepared to undertake the tasks necessary to permit retail competition, was of further concern. In the early 1990s, it was anticipated that recovery of stranded costs would pose a major challenge to any restructuring efforts. A number of the investor-owned utilities were involved in nuclear power plants, with generating capacity costs that were far in excess of market values. However, at the time restructuring commenced, the price of natural gas (the fuel of generating units normally operating at the margin in ERCOT and thus a key determinant of electricity market prices) was at a level that made nuclear generation appear attractive. While a variety of regulatory assets3 required attention, the treatment of 2 El Paso Electric Company was sparred competition due to its emergence from bankruptcy. However, it was originally hoped that competition would be introduced in the Entergy/Gulf States, Xcel/ Southwestern Public Service Company, and AEP/Southwestern Electric Power Company areas around the same time that retail competition was introduced into the services areas of investor-owned utilities in the ERCOT market. 3 Many of these regulatory assets were associated with costs that utilities had incurred in an earlier period. The recovery of these costs through rates was to occur in future years.
stranded costs associated with nuclear power plants failed to pose a great hurdle. In general, reform of the wholesale market preceded the introduction of customer choice at the retail level. 3.1. The wholesale market Rather than adopt a market model tested in another state or country, the policy makers and lobbyists responsible for crafting SB 7 (SB 7, Chapter 39, Subchapter A) focused on avoiding the market structural flaws that they anticipated would emerge in California and other markets. The resulting market structure is vaguely (though unintentionally) similar to the structure of the electricity market in Norway. The ERCOT wholesale market was designed to foster bilateral contracts between PGCs and REPs in order to reduce consumer exposure to hour-to-hour fluctuations in electricity prices.4 Unlike the failed California electricity market, the ERCOT ISO does not operate a centralized spot market for power (but does operate a balancing energy market with some similar attributes). Initially, ERCOT required that qualified scheduling entities (QSEs) submit ‘‘balanced schedules’’ on a dayahead basis to demonstrate that the QSE had arranged for sufficient generation resources and ancillary services to meet the expected demand it had committed to serving. Rarely are next-day forecasts of load or 4 Market rules are presented in detail in the ERCOT Protocols. For a current version, see www.ercot.com.
ARTICLE IN PRESS 18
J. Zarnikau / Energy Policy 33 (2005) 15–25
resources completely accurate. Consequently, ERCOT forecasts likely imbalances between supply and demand on an hour-ahead basis, and procures any additional generation (balancing up) or generation reductions (balancing down) that may be necessary in order to better match supply and demand on a near-real-time basis (i.e., with a notice period of between 10 and 20 min). QSEs with additional generation (beyond that necessary to meet the needs identified in its schedules) or load curtailment capability are encouraged to submit offers for balancing up energy to ERCOT. Less than 5% of ERCOT’s total generation requirements are satisfied through balancing energy. Balanced schedule requirements were relaxed on November 1, 2002, to permit load serving entities (LSEs5) and retail customers an opportunity to designate the balancing energy market as a source of a portion of the LSE’s generation portfolio. It was also hoped that relaxation of the balanced schedule requirement would encourage the establishment of private spot markets for generation. A spot market would improve price signals and transparency, encourage demand side response, and foster more efficient use of available system resources. While the private power exchanges introduced by Enron and Automated Power Exchange in 2001 failed to attract enough participation to remain commercially viable, it was hoped that relaxation of the balanced schedule requirement would facilitate renewed interest in the establishment of such private exchanges. Following price spikes in the balancing energy market in late February 2003, the ERCOT Board of Directors (ERCOT, 2003) imposed a requirement that no more than 10% of a REP’s generation requirements could be obtained from the balancing energy market without providing additional line of credits.6 ERCOT operates a variety of markets for ancillary services (i.e., operating reserves and other services necessary for the efficient and reliable operation of the power grid).7 While most markets are ERCOT-wide, others are zonal or local and designed to address regional or local transmission congestion problems. Some ancillary services are only procured by ERCOT when adverse weather, transmission congestion, or other reliability problems are anticipated (e.g., replacement capacity and out-of-merit-order energy and capacity), while others are procured on a routine daily basis (including regulation services and responsive reserves). QSEs representing PGCs make offers to provide ancillary services on a day-ahead basis. Most ancillary services markets are hourly. In general, these markets 5
LSEs encompass REPs as well as non-opt-in entities, such as municipal systems and rural electric cooperatives, that make retail sales. 6 Resolution from the ERCOT Board of Directors, March 18, 2003. 7 Chapter 6 of ERCOT Protocols at www.ercot.com.
are not very liquid, since most LSEs rely upon bilateral contracts to self-arrange most of their ancillary service needs. In the ERCOT next-day ancillary services markets, the prices of such services may be affected by such factors as the supply and demand for available power plant capacity that is not fully loaded or scheduled to provide generation, and the market power and bidding strategies of generators. ERCOT creates a bid stack or supply curve of all offers to provide ancillary services obtained from QSEs, ordering all offers from lowest to highest. Offers are accepted until the market requirement is met. All winning offers receive the market-clearing price. The QSEs associated with LSEs that are deficient in ancillary services are billed for the costs that ERCOT incurs in procuring these services on behalf of the LSE. In a move widely criticized by power generators, the PUCT placed a temporary offer cap on wholesale electricity generation prices of $1000 per MWh and $1000 per MW for ancillary services just before the new wholesale market opened on July 31, 2001.8 Despite many other safeguards, the state’s regulators remained uneasy about turning over wholesale electricity prices entirely over to the forces of competition in a new and untested market structure. The management of transmission congestion has proven to be a key challenge in all restructuring efforts. Congestion arises when the schedules submitted by QSEs imply power flows that would exceed transmission line limits, resulting in the re-dispatch of generation units. Congestion costs represent the increased supply costs attributable to the transmission constraints. Initially, any congestion costs were simply uplifted to the market and assigned to QSEs in proportion to their load of the LSEs they represent. As congestion costs rose and gaming opportunities became apparent, this was replaced, effective on February 15, 2002, with a zonal congestion management system that better assigns congestion costs to the entities responsible for creating the congestion (at least at a zonal or regional level). ERCOT’s zonal approach to congestion management contrasts with other competitive markets in the US and the FERC’s proposed Standard Market Design (SMD). However, zonal or flowgate approaches are popular in a number of countries outside of North America. Initially three, and later four, congestion zones were established to ration the use of the transmission system during periods of binding transmission capacity constraints. Congestion between zones is managed through the deployment of balancing energy and other means. QSEs pay for congestion costs based on the QSE’s impact on commercially significant transmission constraints (CSCs) and the constraint’s shadow price or marginal 8 Typically, wholesale electricity prices range from the high 20s to mid 30s ($/MWh).
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
cost. Transmission congestion rights (TCRs) are auctioned to the highest bidder for monthly or annual periods and provide suppliers with a means of hedging their inter-zonal congestion cost risk (ERCOT, 2001). Congestion within each zone is managed through ERCOT’s use of out-of-merit-order (OOM) instructions. Under an OOM instruction, a resource (i.e., a power plant or an interruptible load) that is not already scheduled for deployment may be deployed by ERCOT to address a transmission congestion problem. OOM costs are uplifted to all market participants, i.e., these costs are not yet directly assigned to the entities responsible for imposing the costs. In order to dilute market power, no generator is permitted to control over 20% of the installed generating capacity in ERCOT. Further, the larger utilities were required to auction off ‘‘entitlements’’ to a share of the generating capacity for which they retained ownership. Each PGC associated with a utility with at least 400 MW of Texas-jurisdictional installed capacity must sell at auction entitlements to at least 15% of that capacity. In order to satisfy social and environmental goals and constrain demand growth, 10% of the growth in electricity demand must be met through energy efficiency programs that are administered by the TDSPs. Also, a renewable energy portfolio standard was imposed to increase the State’s renewable energy generating capacity by 2000 MW by 2009. 3.2. Retail market design Retail price caps were imposed on the prices charged by REPs affiliated with the incumbent utility (the ‘‘AREPs’’). AREPs were required to reduce the electricity prices charged to residential and small commercial customers9 by 6%, adjusted for fuel rate revisions and certain stipulated base-rate reductions not yet in effect by January 1, 1999. The resulting price provides a benchmark price-to-beat (PTB) for potential competitors. This PTB remains in effect for five years. However, the incumbent utility’s REP can begin charging rates other than the PTB after 36 months or when the AREP loses at least 40% of its residential and small commercial customer load to competitors. After either of these events occurs, the PTB establishes only a ceiling, and the AREP may also offer lower prices. Larger energy consumers in Texas received no price cap protection. Adjustments for the fuel portion of the PTB are limited to two changes per year, unless an AREP is unable to maintain its financial integrity under the prevailing PTB rates or if transmission and distribution costs significantly change. 9 In Texas, the PTB applies to customers with a billing demand below 1 MW.
19
The PUCT designated ‘‘providers of last resort’’ (POLRs) to ensure that all Texans received electric service in the event that their REP went out of business or pulled out of the market. Initially, customers that failed to pay their electric bills were also dropped to the POLR, but later the POLR rules were redesigned so that such customers were dropped to the AREP. Under the current POLR rules, a customer whose electricity contract with a competitive REP (CR) expires is sent to the POLR if the customer fails to renew the contract or exercise any other electricity choice. The energy consumption and billing demand of energy consumers with a peak demand of over 1 MW is measured with interval data recorders. Statistical load profiles were developed for smaller customers. The assumed profile for each of the profiled customers is estimated on a day-ahead basis using a spreadsheet which predicts the profile based on forecasted weather, day type, and other factors. In some respects, the ERCOT organization has assumed a greater role in retail market operations than have ISOs in other restructured markets. The switching of customers from one REP (e.g., the AREP) to another REP (e.g., a CR) requires the use of ERCOT’s customer databases and systems. ERCOT serves as the Central Registration Agent. Customer switches require completion of a large number of electronic transactions via the Texas Standard Electronic Transactions (Texas SET) system. A switch request is first sent by a REP who has signed up a new customer to ERCOT. ERCOT confirms the apparent validity of the switch request and forwards it to the appropriate TDSP. The TDSP checks the switch request and provides a confirmation to ERCOT along with information pertaining to the next meter read date. ERCOT then notifies the REP gaining the customer and the REP losing the account. Meter reads taken by the TDSPs are sent to ERCOT, which then forwards billing data to the appropriate REP. The ownership of meters will become a competitive service on January 1, 2004 for commercial and industrial customers, and will become a competitive service for residential consumers on a later date. REPs are responsible for collecting from their customers various delivery charges to compensate the owners of the transmission and distribution system for its use, as well as contributions to the System Benefit Fund charges, nuclear decommissioning costs, any transition cost or stranded cost charges, and other charges approved by the PUCT. The Systems Benefit Fund was established to fund programs to assist low-income families, provide customer education regarding customer choice, and compensate local school districts for any tax losses resulting from restructuring. In hopes of encouraging competition for residential energy consumers, REPs that serve more that 400 MW
ARTICLE IN PRESS 20
J. Zarnikau / Energy Policy 33 (2005) 15–25
of load and fail to make at least 5% of their sales to residential customers face a penalty.
Balancing Energy Prices Houston - Week of February 23, 2003 vs Average Price for Previous 12 Months
$1,000
4. Market performance
$ per MWh
This section reviews the performance of the Texas market since restructuring began and progress toward meeting the goals of lower electricity prices and expanded choices, while preserving the historically high levels of customer service. The performance of the wholesale market is first reviewed, followed by a review of retail market performance and institutional impacts.
12-Month Average $31.32
$800
$600
$400
$200
4.1. Wholesale market performance The restructuring of the wholesale market is generally regarded as a success. Reliability has been maintained, and the problems that plagued the California market have been largely avoided. As natural gas prices increased following restructuring, the PTB was raised accordingly, thus preventing the type of price squeeze between wholesale costs and retail prices that financially damaged the retail operations of the incumbent investor-owned utilities in California. Volatility in wholesale market prices have harmed REPs that were not well hedged (forcing one into bankruptcy), but have not cause the widespread damage that resulted from price spikes in California, where the majority of retail power requirements were procured through a centralized power exchange. Part of the relative success of the wholesale market restructuring is a direct result of the high reserve margins that Texas enjoyed at the start of restructuring. Due to the surplus generating capacity, prices remained generally low. This is fortunate, since appropriate generation adequacy mechanisms were still under debate in early 2003. Delays were encountered in implementing the systems necessary to consolidate ten utility control centers into a single control center. Numerous changes in market procedures were required as problems became apparent. Several PGCs or power marketers allegedly discovered a market flaw that permitted them to reap profits by over-scheduling generation in August 2001, thus prompting inquiries from the PUCT staff (PUCT, 2001a, b). Four of the six QSEs accused of this practice—American Electric Power Company, Mirant, Reliant, and TXU Electric—eventually agreed to return over $10 million to the market. A tentative settlement has also been reached with Enron Power Marketing. Three significant price spikes in ERCOT’s wholesale markets have occurred since the opening of the market. On the first day of the restructured market, July 31, 2001, prices in the markets for non-spinning reserves and responsive reserves ancillary services shot up to the
$0
2/23/0
2/24/03
2/25/03
2/26/03
2/27/03
2/28/03
Fig. 2. Balancing energy prices, Houston—Week of February 23, 2003.
price cap of $1000 per MW when the largest power producer, TXU Electric, failed to submit its power schedules and offers into ERCOT by the market’s deadline. The two later price spikes were largely the result of poor weather forecasts. The price caps were reached in late April 2002 during a week of unseasonally warm weather and delays in introducing interruptible loads into the new wholesale market as a potential resource. In late February 2003, colder than anticipated weather struck North and Central Texas and gas curtailments affected some generating units while a number of large generating units were down for maintenance. This propelled balancing energy and responsive reserve prices to their capped values (Saathoff, 2003). Balancing energy market prices set during this week are depicted in Fig. 2. ‘‘Hockey stick bidding’’10 by generation suppliers contributed to the price spike (PUCT, 2003a). The legislative mandate promoting renewable energy projects, coupled with uncertainty regarding the possible expiration of the federal production tax credit for renewable energy caused a boom in the construction of wind-to-energy projects. By late 2002, roughly 1000 MW of renewable energy capacity had been completed, greatly exceeding the year-end goal of 400 MW. Yet the construction of renewable generating capacity outpaced the construction of the necessary transmission capability, highlighting the absence of coordination between generation siting and transmission 10 This refers to the practice of submitting a small portion of a bidder’s resource fleet to the market at a very high price, in hopes that the small-high price increment will set the clearing price for the whole market.
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
11
Synchronous Interconnection Committee (1999).
Price of Responsive Reserves and Non-Spinning Reserves April 28, 2002 through May 1, 2002 $1,000
$800
$ per MW
planning and an absence of proper pricing signals to guide investment siting decisions. In the McCamey area of West Texas, 758 MW of wind-to-energy capacity was constructed in an area with a transmission export capability of only 400 MW. Some doubt remains whether ERCOT’s wholesale market will prove workably competitive in the longer run. Simple measures of market concentration using Hirfindahl-Hirschman Index (HHI) calculations suggest that the ERCOT market is either highly concentrated or moderately concentrated (Zarnikau and Lam, 1998). The staff of the PUCT has observed that ERCOT is probably the most concentrated of the deregulated wholesale markets in the US (PUCT, 2003b). The PUCT staff has also examined market concentration in sub-markets within ERCOT.11 Illiquid markets and oligopolistic market power tend to yield volatile prices. ERCOT has been slow to introduce demand-side response programs and to introduce demand-side resources into ancillary services markets. Interruptible customers are slowly being introduced into ancillary services markets to permit their interruptibility to compete head-to-head with an offer from a power plant to provide generation or an operating reserve. In some of ERCOT’s markets, a reduction in demand or the ability to interrupt customer demand (a ‘‘load’’) may be just as valuable (and in many cases, more valuable) than an increase in generation supply or the availability of additional power plant capacity. In mid-May 2002, interruptible and curtailable loads were permitted to participate in the market for responsive reserves as a resource on a limited basis, and interruptible loads were introduced into the markets for non-spinning reserves and replacement capacity in October of 2002. By March 2003, nearly 1000 MW of interruptible loads had been registered to participate in ancillary services markets. Yet the amount of load that may be interrupted or curtailed remains far below pre-restructuring levels of roughly 3500 MW (if all loads served under interruptible service tariffs, group load curtailment programs, direct load control, and energy storage devices were counted). During the first year of wholesale market operations, price reversals occurred in many intervals. Price reversals occur when the market price for an inferior service (e.g., non-spinning reserves) exceed the market price in a superior service (e.g., responsive reserves). An example is shown in Fig. 3 for the April 2002 price spike. This problem is being addressed through the introduction of a simultaneous procurement auction process which will optimize procurement of ancillary services by assigning resources offered to multiple markets to the market where they should have the greatest value. Texas policymakers recognize the importance of a strong transmission system to minimize transmission
21
$600
$400
$200
NonSpinning Reserve
$0
4/28/02
4/29/02
4/30/02
5/01/02
Responsive Reserve
Fig. 3. Price of responsive reserves and non-spinning reserves: April 28, 2002–May 1, 2002.
congestion, and a construction boom in transmission lines is underway. Nonetheless, transmission constraints within the ERCOT market have proven to be a greater problem than originally appreciated, particularly in the Dallas-Fort Worth area, the Rio Grande Valley, Laredo, and West Texas. While most of the new markets for generation and ancillary services were designed to be ERCOT-wide, moving power from certain power plants to energy consumers has proven to be a formidable task. The cost of paying certain generators to produce power just to relieve transmission congestion quickly exceeded early estimates.12 Wind power generators in West Texas keep overloading the only transmission line from their sites to the rest of the market. Congestion costs totaled about $220 million between July 31, 2001 and April 1, 2003. There is growing dissatisfaction with the present approach to congestion management. While congestion between regions or zones is now being managed in a reasonable manner, the costs associated with managing local congestion costs are still being uplifted. Some market participants suggest adopting the method used in PJM; that is, locational marginal pricing (LMP). The PUCT has expressed interest in moving toward some type of nodal pricing which would better assign all congestion costs to the market participants responsible for creating congestion. Some power from cogeneration facilities has yet to find a home under the new market structure. Under federal law, utilities are obligated to purchase excess cogenerated power from qualifying facilities (QFs) at a price no higher than the utility’s avoided cost. However, under the new market structure, the regulated utility is a TDSP that has no need for generation and has no 12 In California, Duke Power and Enron received payments from all market participants to relieve transmission congestion that they allegedly had artificially created (the so-called ‘‘dec game’’). Concerns have been expressed that similar behavior could occur in Texas.
ARTICLE IN PRESS 22
J. Zarnikau / Energy Policy 33 (2005) 15–25
avoidable generating capacity and energy costs. Thus, the PUCT and FERC have reached an impasse over how to treat cogeneration from QFs in the new market. Historically, the PUCT could ensure a minimum level of planning reserves by requiring each of the larger vertically integrated utilities to maintain 15% reserve margins. It has proven difficult to enforce generation adequacy standards under the new market structure. Various proposals are still being considered. However, there may not be an urgency to finalize a plan given existing significant excess capacity. ERCOT’s reserve margins are projected to remain above 30% until 2008. Overall, wholesale market operations have proceeded fairly well. Reliability has been maintained at acceptable standards and competition has increased. The wholesale market design is certainly not perfect—gaming opportunities were quickly discovered, the congestion management system fails to appropriately assign costs in an economically efficient manner, generation siting decisions have created market problems, and there have been setbacks in the areas of generation and transmission planning. Yet, ERCOT’s wholesale market prior to restructuring had its own set of problems. Market participants remain generally optimistic that the remaining transitional problems can be resolved. However, further movement toward a nodal system of congestion management could pose a major challenge. 4.2. Retail market performance ERCOT has had a great deal of difficulty in performing many of the customer service and billing activities that the vertically integrated utilities had performed so well and had been largely taken for granted. Some of the tasks that proved formidable to ERCOT included assigning account numbers (‘‘ESI IDs’’) to new premises, customer switching, collection and distribution of billing data, and disconnection and re-connection of service (‘‘Move-In, Move-Out’’). Customer switching problems have been traced to many causes, including software failures, vague language in ERCOT’s Protocols regarding when a TDSP can reject a switch request, higher-than-anticipated traffic on the ERCOT portal (which provides necessary information to REPs about specific customers), errors in ERCOT’s ZIP code database (which was used as a check to verify the validity of information pertaining to a customer), delays in creating ESI IDs for new buildings and premises, and typographic errors in switch requests. In March 2002, there were about 8000 pending switch requests that seemed to be ‘‘stuck’’ in the switching process.13
Most of the delays appeared to be associated with situations in which ERCOT’s records did not match those of the TDSPs.14 REPs were not certain which customers they had, and for which customers they were responsible for procuring and scheduling generation resources. Through the Market Metrics project, samples of transactions were followed through the switching process, in order to pinpoint problems. It was found that only about half of switching transactions were actually getting completed within a twelve day time frame during Spring of 2002, and of the transactions that were successfully completed, only about one-half were completed within the five-day timeline target established in ERCOT’s Protocols. Many of the switch requests were rejected by the TDSPs due to bad REP Duns numbers (identifiers assigned to REPs), bad dates for the switch request,15 problems with the computer systems at Oncor (a division of TXU and the largest TDSP), duplicate transactions, and indications that the meter had been removed from the customer premise. Because of the delays encountered in processing switch requests, TDSPs were eventually required to backdate valid switch requests in cases where the request should have gone through, but failed to be completed due to a problem with ERCOT’s systems. Delays in processing switch requests caused tremendous problems. Because REPs were not sure which customers they really had, they were uncertain of how much load they were required to schedule power and arrange ancillary services for. Thus, on many occasions, no REPs or multiple REPs were scheduling power for the same customer. In early 2002, a large number of customers were receiving electricity, but had not selected a REP nor had otherwise been assigned to a REP. American Electric Power Company had over 10,000 customers in this group in March 2002. Many of these customers received free electricity. In some cases, customers called the TDSP directly (rather than a REP) to request service. Because REPs were having difficulty starting service for new customers, some of the TDSPs (sympathetically) initiated service for the new customer even without a request from a REP. In other cases, new customers received service that was initiated for a previous tenant or homeowner. Because of delays in getting new service initiated, the PUCT asked utilities to cease disconnecting service when a customer requested a disconnection. Thus, electricity continued to be available in dwellings between tenants. The new tenant was supposed to select a REP and the REP was supposed to notify ERCOT that a new tenant was to be billed for electricity. 14
13
The source of this information is data presented at Retail Market Subcommittee (RMS) meetings during the Spring of 2002.
RMS meeting during the Spring of 2002. For example, CenterPoint Energy received one switch request dated 1924. 15
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
However, there was no incentive for a new tenant to do so. If the tenant took no action, the tenant would continue to receive free electricity. Consequently, anyone that wanted free electricity could simply request service disconnection (which wouldn’t happen), and would no longer be billed for the continuing electric service. Billboards started sprouting up around the State reading: ‘‘Call this number and find out how to get free electricity.’’ Because of the problems in collecting meter read data from the TDSPs and distributing it to the REPs and the uncertainty over who actually had various customers, many customers did not receive electric bills for several months in 2002. Despite the problems associated with customers switching and billing, retail competition clearly provided noticeable benefits. New choices were introduced by new retailers, who included independent REPs (e.g., Green Mountain Energy), affiliates of utilities that previously had no operations in ERCOT (e.g., Sempra, Xcel Energy Retail Services, Entergy Solutions, Strategic Energy, and Constellation), and independent power producers or oil and gas company affiliates that entered the retail market (e.g., Dynegy, Calpine, Tenaska, Tractabel, and Coral), and new firms (e.g., Utility Choice, GEXA, and Texas Commercial Energy). In March 2003, 30 REPs were certified to provide electricity at the retail level to commercial customers, while 11 were certified to serve residential customers (www.powertochoose.org\yourchoice\yourchoiceframe. html). Much of the greatest competition was simply from AREPs competing outside of their traditional service areas (e.g., TXU Energy Solutions, Reliant Energy Solutions, and First Choice Power competing in each other’s former retail service areas). About 7% of residential customers affected by retail competition switched to a different REP by the end of 2002 (PUCT, 2003e, undated). With no price-to-beat protections and often with greater opportunities for savings, about 20% of industrial (primary and transmission voltage) customers accounting for about 60% of the total energy consumption in that group had switched by the end of 2002 (PUCT, 2003a). Clearly, many energy consumers benefited from lower rates. The PUCT estimates that retail customers saved over $1.5 billion in 2002 relative to regulated rates that were in effect in 2001 (PUCT, 2003c). As in other restructured markets, large industrial energy consumers have fared relatively well under restructuring. Commercial and industrial consumers that switched in mid-2002 could expect savings in the 20% range. While residential energy consumers have enjoyed a 6% decrease in the base rates, relatively few have switched. It remains difficult to determine the extent to which smaller customers have benefited from retail competition.
23
By the end of 2002, over 130 load aggregators had registered with the PUCT (2003c, p. 8). Load aggregation has proven effective, but not in the manner predicted. True aggregation (where the load diversity benefits of serving large groups of customers is recognized) is difficult in Texas, for a number of reasons. ERCOT settles each QSE’s ESI IDs separately. If customers under 1 MW without IDRs fall within the same load factor group, their load pattern is assumed to be the same as all other customers in that group. Thus, the load profiling system in ERCOT fails to recognize any load diversity among different customers within the same load factor category, and the true diversity benefits associated with serving a group’s generation needs are difficult to recognize. The transmission and distribution costs associated with serving each commercial customer are billed to the REP based on the customer’s billing demand. Since this billing demand is usually based on the customer’s non-coincident peak, here again load diversity is not taken into consideration. Consequently, thus, true aggregation is difficult unless all members of the aggregation group have IDRs. Yet, load aggregators have been able to deliver significant savings to their clients by improving their client’s bargaining power and negotiating strength. Nonetheless, certain types of group energy procurement programs are working fairly well and customers are benefiting through greater bargaining power and the consulting services available through the programs. In a market where natural gas prices have a considerable impact on electricity retail prices, electricity prices will be volatile. The retail prices quoted by REPs may be honored for periods as short as 24 h. Locking-in prices at an appropriate time has posed a challenge for retail customers. The POLR feature of the market has worked poorly. The POLR was originally designed as a default provider for customers with poor bill payment histories and for customers of REPs that exit the market. Understandably, the concept of charging the same electric rates to those two classes of customers with very different characteristics has not worked. When New Power Company (a former affiliate of Enron) exited from the market and when Texas Commercial Energy shed most of its customers as it filed for Chapter 11 Bankruptcy protection, most customers of those REPs were sent to various AREPs (at lower prices), instead of being directed to the POLR. Very few REPs have expressed any interest in becoming a POLR, given the regulatory constraints on POLR’s rates and the REP’s lack of control over its customer base. Customer service has undoubtedly declined since the introduction of retail customer choice. Confusion continues over which entity to contact in the event of an outage. The marketing tactics of certain REPs have drawn fire. The billing and switching problems have
ARTICLE IN PRESS 24
J. Zarnikau / Energy Policy 33 (2005) 15–25
raised concerns. Some TDSPs have been unable to furnish billing history data in a timely manner, thus hampering retail marketing activities. One of the surprising outcomes from restructuring has been the lack of innovative rate offerings on the part of CRs. Under regulation, the utilities offered a vast array of tariff options for their customers, including interruptible service with different notice periods, curtailment programs, time-of-use pricing, and real-time pricing. While some of the AREPs have custom designed new services to meet specific customer needs, most AREPs have struggled to design simple firm service contracts. So far, the new imaginative product and service offerings that were supposed to emerge from the competitive retail market have failed to materialize. The unbundling process created a variety of problems as well. The PUCT sought to restrict the TDSP’s contact with ultimate retail customers and prevent the TDSPs from providing any services which could potentially be provided by firms in competitive generation or retail markets. However, the REPs and PGCs have shown little interest in providing security lighting, energy efficiency services, transformers on customer premises, and similar services. Street lighting seemed to get lost in the shuffle. There has been confusion regarding whether analysis and information based on metered data (e.g., pulse outputs) is a competitive or regulated service. Consequently, there have been gaps in services that energy consumers traditionally expected in Texas. Many REPs clearly underestimated the challenges involved in earning a profit in a competitive retail electricity market. The traditional utility suppliers had historically enjoyed favorable customer satisfaction ratings. The CRs had little name recognition in Texas prior to restructuring. The CRs found it difficult to compete with the AREPs on the basis of price, given the AREP’s access to relatively low-cost generation from nuclear, coal, and lignite plants. For a short period of time, Texas Commercial Energy was able to compete on the basis of price, but its absence of any hedging strategy eventually caught up with it and sent the upstart into bankruptcy. A number of REPs have already terminated efforts to recruit additional customers after failing to achieve profit targets or after running into credit problems, including AES (which later sold its retail operations to Constellation), and Dynegy. American Electric Power Company decided to transition out of the retail market before retail choice was even initiated— most of its remaining retail customers are being switched to Centrica. 4.3. Institutional impacts An objective of restructuring was to reduce the degree of government control over certain activities. Yet, the shift in power from the PUCT to ERCOT and the
market in general has been greater than planned, in some respects. In the early 1990s, ERCOT had a staff of three people with responsibility for coordinating meetings among the utility members of the reliability council and filing reports with the National Electric Reliability Council and various government agencies. By April 2003, ERCOT had grown into a fairly large organization with over 125 members (e.g., TDSPs, LSEs, PGCs, and industrial energy consumers) and a staff of over 300 budgeted to reach to 400 by the end of 2003. As might be expected when an organization grows as fast as ERCOT, the organization has faced a number of problems related to its leadership, staffing, and direction. In early 2002, while ERCOT was experiencing its worst customer switching and billing problems and complaining about budget limitations, the organization was funding a minor league baseball all-star game, a minor league ice hockey team, and a lavish Christmas party for its staff. Members of the Texas Legislature have questioned the competence of the organization’s leadership. The stakeholder process that has been used to develop ERCOT’s Protocols and Operating Guides and review the work performed by consultants has worked fairly well. Yet safeguards may be necessary to ensure that the stakeholder process does not become a cartel, with a few powerful market participants with significantly greater resources exercising undue control over the process and outcomes. The PUCT has clearly seen its power and authority diminish. While ERCOT theoretically reports to the PUCT, the Commission’s regulatory control over the market has greatly diminished. Historically, the Commission could impose financial penalties on a regulated utility that failed to comply with Commission orders. But, if ERCOT stakeholders or the ERCOT staff do not want to follow a Commission order, there is little the Commission can now do. The PUCT cannot effectively impose a financial penalty on ‘‘the market.’’ While most other markets in North America have established market monitoring organizations within the ISO or regional transmission organization, ERCOT’s market monitoring function resides at the PUCT. The PUCT established a new Market Oversight Division (MOD) in August 2000 with responsibility for market monitoring activities within ERCOT Market. In addition, a new Section, Retail Market Oversight, was created in the Electric Division to address retail market monitoring issues. While assigning market monitoring to the PUCT presents some advantages (e.g., providing a more independent check on market activities and ERCOT’s implementation of market rules combined with enforcement authority), the PUCT’s funding and resource constraints have posed a challenge. The need for additional resources to support PUCT market
ARTICLE IN PRESS J. Zarnikau / Energy Policy 33 (2005) 15–25
monitoring functions are recognized by the Texas Legislature and a decision has been made to provide additional funding through the System Benefit Fund. MOD has selected a consulting firm to enhance its market monitoring capabilities.
5. Overall assessment It is far too early to determine whether Texas has succeeded in designing a competitive electricity market that will result in lower energy costs and greater choices for consumers without sacrificing reliability and customer service. Even if ERCOT continues to out-perform other restructured markets in North America, it may be difficult to determine whether its success is due to its market design or simply the setting and the circumstances in which it has developed. As in other restructured markets, the beneficiaries of retail competition have been industrial and commercial energy consumers. They have realized significant energy cost savings by switching suppliers. The number of residential consumers that have switched retail providers is quite small (yet higher than in many other markets offering customer choice). Indeed, new retail providers have been attracted to the ERCOT market. Yet, most are targeting industrial and commercial customers. Some retailers have left the market, due to credit problems, failure to meet profitability targets, or bankruptcies. Aside from a couple of ‘‘green power’’ offerings, we have not seen the innovative and creative pricing and services that competition promised. Many of ERCOT’s biggest problems resulted when it assumed the role of Central Registration Agent. The ERCOT organization did not have adequate resources, information systems, and expertise to process switch requests, assign ESI ID account numbers, get service turned on in new buildings, and funnel billing data from the TDSPs to the appropriate retail organizations. This resulted in long delays and errors in switching and billing activities, and ultimately, deteriorated customer satisfaction. ERCOT has faced a lot of problems and constantly modified its systems to address these problems. ERCOT and Market Participants have shown a great willingness to explore ways to improve ERCOT systems and enhance the operation of its competitive electricity system. ERCOT has avoided the market meltdown suffered in California. But it is debatable whether these problems have been avoided due to a better market design (e.g., greater reliance on bilateral contracts to hedge wholesale price risks and price-to-beat rates that can be adjusted for fuel market changes), a better market climate (e.g., higher generation reserve margins and a stronger
25
transmission system), or other factors (e.g., greater scrutiny following California’s problems, an absence of federal regulatory jurisdiction, or a different set of market participants). Most likely, it is a combination of many factors. A key lesson learned was that even after the market opened to wholesale competition and retail customer choice, market design activities continued. Some very major changes have been implemented in ERCOT after market open, including changes to balanced schedule requirements, major revisions to the POLR rules, new procedures to assign resources to ancillary services markets, and changes to congestion management. Further sweeping changes to congestion management may be pursued in the future. While these continuous changes create major challenges, they clearly demonstrate that ERCOT and its Market Participants have shown high willingness to explore ways to improve ERCOT’s systems and enhance the operation of its competitive electricity system. Despite the work completed during these initial months, there clearly remain a number of challenges ahead for the establishment of an efficient electricity market in Texas.
References Center for Advancement of Electricity Markets, 2002. Retail Energy Deregulation Index. ERCOT, 2001. A guide to how the Electric Reliability Council of Texas (ERCOT) facilitates the competitive power market, Version 1.2. ERCOT, 2003. Protocols, www.ercot.com. Federal Energy Regulatory Commission, 2002. Docket No. RM01-12000: Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design. PUCT, 2001a. Power to Choose: FAQ, www.powertochoose.org/ whatschanging/safetyframe.html. PUCT, 2001b. Docket No. 25755: PUC investigation into overscheduling in ERCOT in August 2001. PUCT, 2003a. Market oversight division, analysis of balancing energy price spikes during the extreme weather event of February 24–26. PUCT, 2003b. Market oversight division, comparison of market designs. Project No. 26376: Rulemaking Proceeding on Wholesale Market Design Issues in the Electric Reliability Council of Texas. PUCT, 2003c. Scope of competition in electric markets in Texas. Report to the 78th Texas Legislature. PUCT, 2003d. Electricity choice: Texas is different from California, Undated. PUCT, 2003e. February 2003 Report card on competition, undated. Saathoff, K., 2003. ERCOT Staff, Operations Update, Presentation to ERCOT’s Technical Advisory Committee. Synchronous Interconnection Committee (1999). Report to the 76th Texas Legislature: Feasibility Investigation for AC Interconnection between ERCOT and SPP/SERC. Zarnikau, J., Lam, A., 1998. Market Power and Market Concentration in Texas (ERCOT). Electricity Journal. Zarnikau, J., Reilly, R., 1996. The evolution of the cogeneration market in Texas. Energy Policy.