The requirement in Order 888 that the public utility members of tight pools file reformed power pooling agreements no later than December 31, 1996 encouraged some entities to file proposals with FERC to create ISOs. Establishment of an ISO was one option for a power pool agreement to meet the requirements for open, nondiscriminatory membership. The key ISO principles put forth by the Commission in Order 888 addressing power pools included:
ISO governance should be structured in a fair and nondiscriminatory manner. An ISO should be independent of market participants. The ISO's rules should prevent control, and appearance of control, of decision making by any class of participants.
An ISO and its employees should have no financial interest in the economic performance of any power market participant.Transmission owners need to be able to hold the ISO accountable in its fiduciary role but should not be able to dictate day-to-day operational matters.
An ISO should provide open access to the transmission system pursuant to a single, unbundled, grid-wide tariff. The portion of the transmission grid operated by a single ISO should be as large as possible, and the ISO should schedule all transmission.
An ISO should have the primary responsibility in ensuring short-term reliability of grid operations.An ISO should oversee all maintenance of the transmission facilities under its control. The ISO should be responsible for developing and implementing curtailment policies to ensure the security of the system.
An ISO should have control over the operation of interconnected transmission facilities within its region.
An ISO should identify constraints on the system and be able to take operational actions to relieve those constraints. The ISO may need to exercise operational control over generation facilities in order to regulate the power system. An ISO will provide, or cause to be provided, ancillary services.
An ISO should make transmission system information publicly available on a timely basis via an electronic information network.1
A number of ISO proposals – California ISO (CAISO),2 PJM ISO (PJM),3 ISO New England (ISO-NE),4 the New York ISO (NYISO),5 and the Midwest ISO (MISO)6 – were accepted by the Commission, and these organizations (except for MISO) began operation, with various degrees of success (the California meltdown would not become apparent until 2000). In addition, the Texas Commission ordered an ISO for ERCOT that became the first established ISO in the United States.7 The PJM, New England, and New York ISOs were established on the platform of existing tight power pools. ERCOT had existed as a loose power pool. In contrast, the establishment of the California ISO was the direct result of a state government mandate. MISO was the product of voluntary actions by utilities in the region, and the lack of a well-organized predecessor explains its convoluted evolution.
For the most part, these markets gradually evolved from a loose power pool to highly coordinated markets. The establishment of formal power pools, and then the mandate of FERC's Orders 888 and 890, shifted control area responsibilities to a central authority. Once the ISO was established, it would run a balancing market that would clear the residual supply and demand in the region, but most trades were either internal (the utility “selling” generation to its distribution function) or between generators and customers (often small utilities with insufficient generation to meet their demand) through bilateral contracting. Over time, these arrangements would coalesce into more formal electricity markets, encouraged by FERC rulings and guidance. State-level restructuring, by opening markets to independent generators, and allowing customers to contract for power, accelerated this development.
PJM began in 1927 when three utilities, realizing the benefits and efficiencies possible by interconnecting to share their generating resources, formed the world's first continuing power pool. Additional utilities joined in 1956, 1965, and 1981. Throughout this time, PJM was operated by a department of one member utility. In 1962, PJM installed its first online computer to control generation. PJM completed its first Energy Management System (EMS) in 1968. The EMS is the information technology system that makes it possible to monitor transmission grid operations in real time. PJM began the transition to an independent, neutral organization in 1993 when the PJM Interconnection Association was formed to administer the power pool.8
On July 24, 1996, nine of the ten members of PJM9 submitted a filing for a proposed comprehensive restructuring of the PJM pool. The proposal provided for a regional market for wholesale electricity and related services, and for transmission service on a pool-wide basis under a single transmission tariff. The market would be operated by an ISO that would coordinate day-to-day control area operations and administer the transmission service.10 Philadelphia Electric Co. (PECO) filed an alternative PJM restructuring proposal. PECO proposed a wholesale energy market, called the Power Exchange, and a regional transmission tariff that would be administered by the ISO.11 The Commission rejected both proposals as failing to meet the Commission's ISO principles. Both proposed ISOs fail to comport with the ISO governance principle because the proposed governance structure precluded meaningful representation by non-PJM stakeholders, nor did the proposals ensure the financial independence of ISO employees. The proposals fell short in numerous other aspects, relating to transmission rates, control of transmission facilities, and congestion management.12
An Order 888 Compliance Filing was submitted in December 1996, with supplemental materials presenting alternative approaches to certain issues proposed by PECO and the Supporting Companies. In November 1997, FERC conditionally accepted a modified PJM proposal, to become effective January 1, 1998, subject to revisions.13 The Filing established an ISO as an independent body to administer the PJM Transmission Tariff, operate the spot energy market, and approve a regional transmission expansion plan. An independent board would be responsible for supervision and oversight of the day-to-day operations. The PJM Operating Agreement also called for the formation of a Members Committee, on the basis of the following sectors: Generation Owners, Other Suppliers, Transmission Owners, Electric Distributors, and End-Use Customers. All transmission services would be subject to a single rate based on the costs of the individual utility's transmission system where the point of delivery is located. LMP would be adopted for calculating and recovering the costs of transmission congestion. Every firm point-to-point and network service under the PJM Transmission Tariff would be awarded fixed transmission rights. The Commission directed PJM to implement PECO's transmission congestion pricing proposal, and to implement Supporting Companies' proposal with respect to options dealing with all other issues.14
The Commission suggested that a multi-settlement system, utilizing both the day-ahead and real-time markets, could provide a mechanism for addressing the risks of uncertain congestion charges. Such a system would allow market participants to commit and obtain commitments to energy prices and transmission congestion charges in advance of real-time dispatch. A multi-settlement system proposal would permit each transmission customer to inform the ISO of the maximum price (including the congestion charge) it is willing to pay. In developing the day-ahead schedule, the ISO would schedule only those transmission customers that are willing to pay the applicable market clearing prices.15 The Commission also approved market-based rates for sales of energy and certain ancillary services in PJM.16
LMP proved to be a superior option to an alternative zonal pricing approach, which, implemented in April 1997, proved to be fundamentally inconsistent with a competitive market. The zonal pricing system allowed market participants the flexibility to choose between bilateral transactions and spot purchases, but did not simultaneously present them with the costs of their choices. The circumstances created a false impression that savings of $10 per MWh or more could be achieved simply by converting a spot transaction into a bilateral schedule. Faced with this perverse pricing incentive, market participants responded naturally by scheduling more bilateral transactions than the transmission system could accommodate. Locational pricing was also applied by PJM for managing interregional transmission loading relief. In addition, the anecdotal evidence suggested that investments in new generation and transmission were being considered with careful attention to the effects of system congestion, as intended.17
The success of the PJM market encouraged additional utilities to apply for membership. They included Allegheny Power in 2002, Com Edison, AEP, and Dayton Power & Light in 2004, and Duquesne Light and Dominion Power in 2005. In 2011, American Transmission Systems, the transmission affiliate of FirstEnergy, and Cleveland Public Power were integrated into PJM.
Although New York was similar to California in that it established an electric market in a single state, there were some significant differences. When the New York utilities sold their power plants, with the exception of Consolidated Edison (Con Ed), they entered into power purchase agreements to buy that power back. New York primarily imports power from Quebec Hydroelectric, which has a tremendous amount of surplus capacity and does not experience the same variability of water flow as is typical in the Western United States. New York also has a public power entity, which can act as a backstop to the market. In New York, transmission constraints were primarily limited to New York City and Long Island.
The NYISO grew out of the NYPP, which had controlled the New York transmission system and the real-time dispatch of the generating units in the state since the 1960s. The NYPP was created after the Great Northeast Blackout of 1965, and was owned by the member utilities in New York (seven investor-owned utilities18 and the New York Power Authority). The Power Pool was structured as a tight power pool, but did not centralize unit commitment and dispatch, unlike NEPOOL and PJM. Units were only dispatched to balance supply and demand after the individual utilities decided which units they would commit to meet the loads of their own customers. NYPP carried out many of the reliability functions normally performed by a control area operator, such as balancing electric system supply and demand in real time, maintaining voltage, monitoring contingencies, managing operating reserves, and dispatching generation. NYPP provided a forum for arranging short-term trades among utilities and allocated the benefits of these trades based on a “split-savings” price formula.19
On January 31, 1997, the Member Systems filed with the Commission a conditional proposal to establish an ISO and form a fully competitive wholesale electricity market in New York. In December 1997, the Member Systems submitted an additional supplemental filing that provided for location-based marginal pricing with three-part bids, day-ahead and real-time markets, transmission congestion contracts, a New York State Reliability Council to establish reliability standards for the bulk power system, and an independent ISO board. The Commission conditionally approved the ISO and the new market.20 Tariff issues, market rules, and a request for market-based rates were approved in January 1999. Market-based rate approval, similar to PJM, revolved around meeting the 20 percent market share threshold, as well as a proposed market-monitoring plan.21
NEPOOL was initially organized in 1971 and has more than 130 members. NEPOOL operated the central dispatch of virtually all of the generation and transmission facilities in New England as a single control area. As the control area operator, NEPOOL assumed responsibility for the minute-to-minute operation of the region's bulk power system, including regulating system frequency, maintaining system voltage, managing interchange between NEPOOL and neighboring power systems, dispatching NEPOOL generating capacity, managing the NEPOOL transmission system, and coordinating daily transmission and generation outages. NEPOOL also provided operational planning services in support of central dispatch (e.g., coordination of annual generator maintenance schedules, transmission facility outage scheduling, administration of bilateral contracts between NEPOOL Participants and non-NEPOOL entities, and short-term and long-term load forecasting).22
NEPOOL filed a comprehensive restructuring proposal on December 31, 1996, in response to the Order 888 deadline, with supplements in 1997. The Commission accepted for filing the NEPOOL proposal and made it effective on March 1, 1997. NEPOOL proposed to transfer operational control of the New England bulk power system to the new ISO. The Commission accepted a negotiated arrangement, leaving market rules primarily under the control of NEPOOL committees.23 On July 1, 1997, ISO-NE was activated.
NEPOOL also proposed that network loads and resources in NEPOOL would be integrated over nine local utility systems after a five-year transition period. A single postage stamp rate would be assessed regardless of the number of transmission systems involved in providing a service. The NEPOOL Tariff also offered nonfirm point-to-point transmission for Through and Out Service, in which power is transported across, or exported from, the pool. The Commission ordered continuation of point-to-point transmission service despite the availability of network service.24
NEPOOL proposed the unbundling of electric services in the NEPOOL control area and the development of competitive wholesale markets for capacity and energy.25 The energy market would be a residual market. Each participant settles through the market the net difference between its energy produced and consumed. The energy market also allowed LSEs to submit bids reflecting the price at which they are willing to reduce load. Each participant is required to bid any capacity that has not been self-scheduled. NEPOOL proposed a one-settlement system where scheduled quantities are settled at real-time prices. At least every five minutes, the ISO calculates a market-clearing price for energy. The price at settlement is the weighted average of these five-minute clearing prices over the hour. NEPOOL would also operate markets for Installed and Operable Capability.26 The NEPOOL Tariff provided that, until January 1, 2000, each transmission customer would pay an “uplift charge” reflecting a pro rata share of redispatch costs incurred as a result of transmission constraints. The interim congestion management proposal would continue in effect as a default method unless the NEPOOL Management Committee agreed to an alternative method.27 The additional expense of redispatch to clear congestion would be uplifted on a pro rata basis to all loads.28
The single settlement proposal was problematic, as the ISO's consultants pointed out. The single settlement system planned at NEPOOL would allow for gaming of the market that could circumvent the requirement to bid all uncommitted capacity into the market. A generator could nominally comply with the requirement by submitting a bid, but then fail to follow the ISO's dispatch instructions in real time to produce the energy consistent with its day-ahead bid. To replace the unproduced energy, more expensive energy would need to be dispatched, which would increase the real-time energy price. A multi-settlement system was not vulnerable to these strategies because prices are locked in a day ahead, removing the temptation to game the real-time market.29 The Commission agreed and required NEPOOL and the ISO to develop plans for implementation of a multi-settlement system and to submit the plans with a revised congestion management plan.30
The Commission granted NEPOOL's request for market-based rates in the ISO-administered markets. The Commission directed NEPOOL to expand its mitigation measures to require bidding into the energy market at the seller's marginal cost. This mitigation measure would limit the bids of sellers found by the ISO to have market power, but it did not cap prices. Sellers should be permitted to receive market-clearing prices, even if the prices exceed bids. The Commission continued to employ its 20 percent market share threshold, along with examination of HHIs. FERC rejected studies by intervenors demonstrating the potential for strategic behavior, relying on market monitoring to prevent the exercise of market power.31
ERCOT is the only major wholesale electricity market that is not under FERC jurisdiction. On or about August 26, 1935, solely to avoid becoming subject to FPC Jurisdiction, certain Texas utilities elected to isolate their properties from interstate commerce. During World War II, these and other intrastate utilities interconnected their grids, forming the Texas Interconnected System. In 1970, members of the Texas Interconnected System as well as municipalities and rural electric cooperatives, all operating on an exclusively intrastate basis, formed ERCOT, a regional electric reliability council reporting to NERC. In 1981, the Interconnected System transferred all its operating functions to ERCOT.32
The autonomous nature of ERCOT was challenged in the 1970s when a group of Oklahoma utilities filed an action asserting PUHCA noncompliance by CSW, because its Oklahoma subsidiaries lacked electrical connections to its Texas subsidiaries. CSW tried to interconnect on the night of May 4, 1976, known as the “midnight connection,” to subject ERCOT to federal jurisdiction and then petition the FPC to order interconnection to the Southwest Power Pool (SPP). The FPC held CSW's constituent utilities to be “public utilities” subject to federal jurisdiction due to their interstate connection, but found that the other ERCOT utilities, which had disconnected shortly after the midnight connection, could not be subjected to federal regulation. The PUCT then ordered CSW to disconnect its Texas utilities from Oklahoma. On July 28, 1980, both CSW and the other ERCOT utilities submitted an Offer of Settlement, agreeing on an asynchronous DC interconnection to Oklahoma because the power flows over a direct-current link could be controlled. FERC accepted the settlement offer.33
In 1995, the Texas legislature, in Senate Bill 373, exempted power marketers and EWGs from being regulated as utilities, but they were authorized to sell only wholesale electric power in Texas. Utilities that owned or operated transmission facilities must provide wholesale transmission access at rates, terms, and conditions comparable to their own use of their system. The PUCT could require utilities (including municipal utilities) to provide access to transmission services to another utility, a QF, an EWG, or power marketer. In 1996, PUCT employed its rulemaking authority under the 1995 amendments to make ERCOT the ISO for Texas.34
Unlike California and the northeast states, high electricity prices were not a motivating force behind the creation of the Texas electricity market. Electricity prices were 10–15% lower than the national average, with industrial customers receiving the greatest discount.35 Deregulation was primarily an insider's game, between the industrials who wanted competition, utilities that wanted protection from financial risks of deregulation, and Enron, which wanted to open up a business opportunity on its home turf.
Enron played a significant role in Texas deregulation, owing to long-standing investments in political influence. Ken Lay had developed a reputation for ruthlessness, using his money and influence to punish state legislators who opposed his company's interests. In Texas, Enron spent $5.8 million between 1998 and 2000 funding state politicians. The company also spent as much as $4.8 million on Texas lobbying. It used its political influence to overcome the resistance of the existing regulated utilities in Texas.36 A longtime supporter of the Bush clan, Lay became a close advisor to George W. Bush and a key source of funds for his first gubernatorial campaign in 1994.37 Bush then appointed Pat Wood III from Port Arthur, a Harvard law graduate with a bachelor's degree in engineering from Texas A&M, to the PUCT. Wood began his public career on the staff of the FERC, serving as legal advisor to Commissioner Jerry Langdon from 1991 until 1993. Lay endorsed Wood for the PUCT job in a letter to Bush in 1994. After four months on the Commission, Bush made Wood the chairman of the PUCT. Wood said that his orders from Bush were clear: “Get us to a market.”38
Enron stepped up its lobbying campaign, buying statewide television and billboard ads hawking competition. Enron funded front groups, such as Texans for Affordable Energy, to stimulate a grassroots call for deregulation. As Enron made inroads with legislators, the IOUs began to see the writing on the wall. Chairman Wood sweetened the deal for the IOUs by suggesting that they might be allowed to recover stranded costs. When the 1999 legislative session rolled around, the big utilities were finally on board. Two bills were introduced in the 1999 session, House Bill 349 (proposed by Dallas Democrat and lawyer Steve Wolens) and Senate Bill 7 (by Waco Republican dentist David Sibley). Some sources claimed industry lobbyists wrote most of the text. Wolens vociferously denied these allegations, claiming he wrote the bill with Pat Wood and, to a lesser extent, Sibley. The Wolens/Sibley plan would freeze electricity rates for five years. At the end of the freeze period, prices would be cut by 5 percent, and then competition would begin. Utilities would be split into three distinct functions: generation, wires, and retail sales. TXU officials vehemently opposed the proposal and vowed that they would fight the deregulation bills if they were forced to sell capacity.39
Large industrials have always had a disproportionate political influence in Texas, and they demonstrated their power by killing an amendment that would have spread the cost of stranded costs on the basis of consumption.40 The eventual demise of the amendment ensured that stranded costs would be allocated on the basis of peak demand, which large industrial customers can reduce easier than residential consumers can. Governor Bush signed SB 7 on June 18, 1999. The Texas Chemical Council hailed the signing of the bill, as the larger companies with cogeneration facilities would be able to sell their surplus electricity for extra revenues.41
As a consequence of Senate Bill 373, the PUC adopted a policy of postage stamp pricing for transmission services. The embedded costs of owning and operating each utility's transmission system are pooled and divided among the utilities that serve loads. Seventy percent of the costs were allocated among transmission customers on the basis of load, and 30 percent on the basis of megawatt-miles of transmitted power.42 In 1999, the Commission adopted new rules that allocated transmission costs 100 percent based on peak demand.43 Postage stamp pricing and socialization of transmission costs across ERCOT removed political barriers to transmission expansion, as it avoided the cost allocation conflicts that have stalled transmission projects in other jurisdictions. Chairman Wood warned in early 2001 that a shortage of transmission lines and power plants could complicate the transition to deregulation. ERCOT, in a report filed in 2001, identified six areas of the state that would require more transmission construction.44 The PUCT encouraged an aggressive transmission construction program to overcome these constraints on the eve of deregulation. Eight of nine major construction projects were completed by December 2002.45
On July 31, 2001, ERCOT consolidated its existing ten control areas into a single control area. Wholesale power sales began to operate under new guidelines, including centralized power scheduling and the procurement of ancillary services. Commercial functions, including the acquisition of meter data and the profiling of electrical consumption, were transferred to ERCOT, and there was statewide registration of retail premises to facilitate the switching of customers between competitive electricity providers.46 Utilities were limited to owning and controlling no more than 20 percent of installed generation capacity within ERCOT. The statute prohibited wire companies from selling electricity or other competitive energy services. Rates were frozen from 1999 through 2002, when competition would start. During the period when rates were frozen, excess earnings were applied to write down stranded costs. SB 7 also provided funds for energy efficiency47 and a system benefit fund to help low-income ratepayers.48
Deregulation in Texas resulted in reorganization. Texas Utilities became TXU, the holding company for Oncor (wires), TXU generation (renamed Luminant), and TXU Retail (renamed TXU Energy). Houston Light and Power became CenterPoint (wires), Reliant Energy (retail), and its generation was spun off in July 2004 to Texas Genco (an entity owned by a consortium of private equity firms) for approximately $3.7 billion. Texas Genco was then flipped to NRG for $8.8 billion a year later. The jump in value can be traced to the rise in natural gas prices from $6 to $12 per MMBtu over this period, which increased the market price of electricity and profit margins for generators with coal and nuclear capacity. HL&P ratepayers were still on the hook for $2.3 billion in stranded costs.49
TXU would be purchased by private equity firms Kohlberg Kravis Roberts, Texas Pacific Group Capital, and Goldman Sachs in a leveraged buyout in 2007, and renamed Energy Future Holdings. The CEO of TXU, John Wilder, received almost $280 million due to change of control clauses in his contract.50 The total cost of the acquisition was almost $47 billion, financed with $8 billion of equity investment and $39 billion of debt.51 The transaction was greased through $11 million in advertising and $6 million in lobbying expenses.52 The deal soon turned sour as projected electricity prices in ERCOT, due to declining natural gas prices, fell well below the levels required to meet debt service requirements.53 Energy Future Holdings restructured its debt a few times in a bid to buy time, paying close to $1 billion in fees, as well as higher interest rates to shift maturity dates.54 Despite these steps, the company declared bankruptcy in 2014.55
Texas established a price to beat, which set electricity rates for incumbent retail providers. The rate was in effect from January 1, 2002 until December 31, 2006.56 The wires companies were also permitted to charge a fee to recover their stranded costs, which were finalized in true-up proceedings in 2004.57 The average rate was 6 percent less than the average rates charged as of January 1, 1999. During the first three years, the price to beat was the only price that could be charged by an affiliated retailer in the incumbent utility's service area. Other retailers could enter and bid customers away, knowing the affiliated retailer could not match their prices. During the last two years of the five-year period, the affiliated retailer was capped by the price to beat, but could offer lower prices.58 ERCOT performs functions in the retail market that were performed by the LSEs in other states that introduced retail competition. ERCOT acts as a neutral third party to perform settlement functions for the retail market. ERCOT also serves as the registration agent for all retail transactions. Customer switch requests, move-in and move-out requests, and monthly electricity usage data flow through ERCOT.59
The combination of an emerging electricity market with growing demand and old plants with high operating costs made Texas an attractive destination for new merchant power plants. Low gas prices made combined-cycle gas plants competitive against older gas-fired facilities and new nuclear and coal plants. Deregulation coincided with an unprecedented power plant construction boom, adding 24,680 MW of new capacity between 2000 and 2004.60 The combination of excess capacity and new transmission provided a buffer for the new market from design flaws.
An unintended consequence of deregulation was the creation of the largest demand response market in the United States. Traditionally, utilities provided “interruptible service” tariffs to generally large industrial customers. In return for the right to interrupt a customer, the utility offered interruptible service customers a discounted rate, usually a reduction in firm demand charges. Before restructuring, the ERCOT utilities reported 3,125 MW of interruptible load in ERCOT, but it was rarely called: for example, in 1999, only 52 MW was curtailed during peak hours.61 To pave the way for retail choice, all tariffs (including interruptible rates) offered by IOUs in ERCOT were terminated. Faced with the loss of these lucrative discounts, industrial customers lobbied for eligibility to provide ten-minute spinning (“responsive”) reserves, and were able to obtain 25 percent of the 2,300 MW responsive reserve market for Load acting as Resources (LaaRs). LaaR requirements included at least 1 MW of interruptible load, with the telemetry to respond to a command to drop load within ten minutes and armed with an under-frequency relay that would immediately drop load if system frequency fell below 59.7 Hz. In 2003, LaaRs became eligible to supply 50 percent of responsive reserves.62
On November 1, 2000, the ERCOT filed its Protocols, and the PUCT approved them on April 11, 2001, and on rehearing on June 4, 2001. The PUCT required a generation bid cap of $1,000/MWh (and $1,000/MW for ancillary services) as a backup stop against the possible exercise of market power, to expire in July 2003. All scheduling of energy or bidding for ancillary services must be done through a Qualified Scheduling Entity. A Scheduling Entity had to meet credit requirements to ensure that it could pay for the ERCOT services it used. Initially, Scheduling Entity were required to submit balanced schedules in terms of loads and their corresponding resources, but this requirement was eventually relaxed. ERCOT compared the sum of these schedules to its own load forecasts, to determine balancing energy and ancillary services requirements. If submitted schedules result in congestion of the transmission system, ERCOT redispatched system resources out of merit order to resolve the congestion.63
When ERCOT began operation, the costs for relieving congestion were “uplifted” based on the market participant's load share. The PUCT required ERCOT to switch to a direct cost assignment methodology, including local congestion costs.64
However, 95 percent of transactions continued to be bilateral contracts between generators and retail electric providers (REPs) or unregulated distribution companies. While this provided a buffer against the impact of price spikes in the spot market, it also led to a thin, inefficient spot market. Price spikes during a three-day winter storm in February 2003 raised concerns of market manipulation.65 The PUCT, following an investigation, concluded that a wholesale market strategy known as “hockey stick” bidding was partially responsible for the price disruptions. The price spikes resulted from one market participant's offering a single MW at $990.66 A Modified Competitive Solution Method was implemented. It precluded hockey stick bids from setting the market price by establishing a lower market price, at the price level at which 95 percent of the bid stack is exhausted. Market participants bidding above that level were paid as bid. The PUCT required the disclosure of market offers in excess of $300/MWh.67
Problems with operations under the zonal system resulted in increasing support to switching to a nodal/zonal system. The PUCT held hearings on this proposal in 2002, and adopted a rule in 2005 directing ERCOT to implement a nodal market design. The original cost-benefit study estimated a cost to ERCOT from $55 million to $70 million.68 The development of a nodal market ran into software snags, partially as a result of poor management, as well as demands from municipals and cooperatives to incorporate their special status and grandfather their existing contracts into the software design. The first nodal budget of $263 million was based on a start date in January 2009. In May 2008, ERCOT officials announced an indefinite delay in the nodal project, because a vendor had failed to deliver the required software. The nodal market began operation in December 2010, with a final cost of $561 million.69
