America’s energy competition laboratory prepares to build.
Hind Farag is Midwest Market Outlook Manager at Global Energy Advisors. Contact her at email@example.com; Gary L. Hunt is president of Global Energy Advisors. Contact him at ghunt@ globalenergy.com.
The Electric Reliability Council of Texas (ERCOT) region remains a living example of how to make a successful transition to restructured wholesale and retail markets for electricity. At the same time, the market continues to witness some significant developments. Despite the historically high levels of generating reserve margins in recent years, the permanence of operating reserve margin sufficiency has come into question by the considerable number of plant mothballs and, more significantly, permanent retirements. Despite that, sights are turning from recovery to the next stage of the power business cycle: The Buildup.
While the market has seen the construction of approximately 24,000 MW since 2000, operators are mothballing and retiring more than 13,000 MW. Recent ERCOT reports have concluded that additional capacity could be required much sooner than previously expected. Global Energy believes, however, that if reserves drop too low, some mothballed plants may be re-commissioned.
Currently, about 1,970 MW (dependable) of capacity is under construction, very much below the more than 23,700 MW since 2000. Between our Fall 2005 and Spring 2006 Market Outlook reports, we identified an additional 529 MW of new renewable generation capacity currently under construction.
By 2008, about 25,000 MW of new generating capacity will have entered the ERCOT markets since 2000. This is a significant amount of new capacity in an area with an expected annual peak load of approximately 61,415 MW in 2006.1 Since most of this new generation is natural-gas-fired, in many cases it has been constructed in the vicinity of load centers. But that is not always the case, as shown in Fig. 2.
Reliability concerns emerged in ERCOT despite the considerable amount of recent capacity additions, as plant operators accelerated their mothballing and retirement activity. By January 2011, more than 13,000 MW of generating capacity in ERCOT will have been retired or mothballed.
In response, ERCOT recently revised its reserve-margin calculation methodology to exclude mothballed capacity from its installed capacity estimates. This revised methodology also includes a new econometric load-f orecasting model that has resulted in significantly lower load-growth projections from previous forecasts. Despite this reduction in peak-load expectations, the exclusion of mothballed units from reserve-margin calculations shows the need for new capacity additions by the end of this decade.
Rising concerns over resource adequacy and reliability have induced the Public Utility Commission of Texas (PUCT) to revive its resource adequacy rulemaking and begin deliberating with stakeholders on mechanisms for en-couraging investment in new entry.2 Generators generally have thrown their support behind installed capacity (ICAP) type markets, while loads and regulators supported energy-only approaches.
In its recently published proposed new Rule 25.505—Resource Adequacy in the Electric Council of Texas Power Region— the PUCT leans toward the energy-only approach for ensuring generation resource adequacy. This PUCT rule introduces the scarcity pricing mechanism (SPM) designed to encourage growth in the supply of generation resources, with a planned implementation of Jan. 1, 2007. The SPM would use system-wide offer caps and resource-specific offer caps ranging between $500/MWh and $3,000/MWh, and phased in between March 1, 2007, and March 1, 2009.
In its 79th session, the Texas legislature reaffirmed and strengthened the PUCT oversight over ERCOT financial and operational aspects.3 As recommended by the Sunset Advisory Commission, the PUCT operation was extended for another six-year term. Further, the PUCT was required to select and appoint an independent market monitor to be supported and funded by ERCOT.
This came at a time when extremely high prices during the fall of 2004 caused some concerns among regulators over possible opportunities for market-power abuse in the region. ERCOT and the PUCT currently are in the process of selecting an independent market monitor (IMM) and designing related processes. In addition to resource adequacy, Rule 25.505 also addresses market-power issues. The proposed rule currently is under revision and is being discussed among market makers, regulators, and participants. Once the rule is finalized, the selected IMM would conduct the market power screen tests periodically and perform related activities.
As reserve margins are expected to fall, power-plant development activity has heated up once more in ERCOT. Currently, about 18,500 MW of new generation is being developed in ERCOT. Of this amount, almost 2,000 MW is under construction and planned to enter the market by 2010. Further, Global Energy expects that in addition to new generating entry, a few of the mothballed generators may elect to re-commission. We have analyzed the expected economic performance for all mothballed capacity in ERCOT and assume that approximately 3,300 MW of the mothballed 7,900 MW (nameplate capacity) would be re- commissioned between 2008 and 2010.
Fig. 3 shows announced power capacity in ERCOT and its construction status since 2000. Although delayed and canceled plants continue to rise, there remains more than 15,400 MW of “planned” capacity additions still in development.
The large amounts of new supply have caused spark spreads for gas-fired generation in the past few years to be lower than the levels sufficient to provide decent financial results.4 However, high temperatures around Texas during much of last summer resulted in very high electricity prices across the region even before hurricanes Katrina and Rita hit. As a result, generators have seen somewhat higher spark spreads. Unlike other markets, such as the Midwest, merchant gas generators are not affected by competitive fuel economics between coal or oil and natural gas. This is caused by the preponderance of natural gas in setting the market clearing prices, which reaches nearly 100 percent of all on-peak hours.
A total of 55,364 MW of new generation has been announced in ERCOT since January 2000. Of this amount, 16,200 MW has been canceled or postponed. The upward pressure placed by the escalating natural-gas prices on generator costs and, eventually, on wholesale power prices and the rising concerns over resource adequacy in ERCOT, coupled with the abundance and much lower cost of coal, continue to direct attention to new coal-fired capacity development. To date, developers in ERCOT announced plans to build about 11,500 MW of coal-fired plants. Around 8,700 MW of these planned additions reflect TXU’s recent announcement to augment ERCOT’s baseload resources by 8,000 to 10,000 MW.
In Global Energy’s Spring 2006 Reference Case forecast for ERCOT, of the announced coal-fired additions we include only CPS’s J.K. Spruce, consistent with our methodology of only including defined-addition units that are under construction. In the long term, we have added about 5,500 MW of generic coal-fired capacity to reflect the coal-fired development activity currently taking place and the undeniable economics of new coal-fired generation.
Many states have established targets for generation by renewable supply resources. In this instance, Texas leads the way with a renewable capacity target of 2,880 MW by 2009, enforceable through various incentives and penalties for non-compliance. In July 2005, the Texas legislature boosted the renewable portfolio standard (RPS) targets to 5,880 MW by January 2015. To fully meet these targets, significant amounts of new renewables still would be required, although interim targets currently are being met. At the same time, it is becoming more and more obvious that new renewables will require new transmission lines. Curtailment and other schemes to pay wind generators for lost generation attributable to transmission congestion have been applied and proposed. The West Texas area has been affected especially by transmission congestion and draws attention to the need to coordinate new RPS standards with new transmission.
A recent ERCOT report indicates that to accommodate the higher RPS targets of 5,880 MW, more than $1 billion of additional transmission investment in West Texas would be needed during the next few years. Another $700 million to $2 billion would be required should the RPS be extended further to achieve a proposed target of 10 percent by 2025.
In Global Energy’s Spring 2006 forecast, we expect that after 2009—when the initial RPS target is hit—an additional 3,300 MW of capacity will be built in ERCOT. This level of additional building is in line with the recently passed Texas RPS expansion law. In total, about 5,922 MW of renewables are being added over the forecast time frame.
Congestion costs in August 2001 set the record when they reached $137 million. These significant congestion costs triggered the direct assignment of interzonal congestion costs to all market participants, leading to the current interzonal transmission congestion rights (TCR) congestion-management model. As a result of the direct assignment, interzonal congestion costs have declined significantly. On the other hand, local congestion costs—including payments for out-of-merit energy (OOME), out-of-merit capacity (OOMC), reliability must run (RMR), and resource specific instructions—have risen dramatically between 2001 and 2004. Between January 2002 and September 2004, local congestion costs averaged more than $25 million per month, while interzonal congestion costs averaged $2.6 million per month. Local congestion is managed by ERCOT by requesting generators to adjust their output.
Since August 2001, ERCOT congestion costs have totaled $1.5 billion. Of this amount, $1.2 billion has been caused by local congestion. This represents more than three times as much as the interzonal congestion costs handled through commercially significant constraints. After peaking in 2003, local congestion costs decreased by 40 percent in 2005 as a result of the recent transmission-system upgrades aimed mainly at alleviating local constraints (see Fig. 4, p. 16).
Congestion pricing in ERCOT has been dominating wholesale market design discussions since 2001. Implementation of locational marginal pricing in ERCOT is expected to occur by the summer of 2009. The congestion-pricing model currently in use does not directly assign local congestion costs to those who cause congestion. Rather, local congestion costs are allocated to all market participants on a pro-rata basis in proportion to the amount of load they represent without consideration to who caused the congestion.
In other markets, the Midwest Independent System Operator began locational marginal prices (LMPs) when it opened its wholesale electricity markets in April 2005, and LMP markets already are in place in New York, PJM, and New England. They also are under development in California and elsewhere.
Global Energy has produced LMP forecasts for ERCOT using our LMP Network Database product (see sidebar, “The Technology Behind Calculating LMPs”).
Fig. 5 illustrates nodal prices at each bus using a price contour during one hour of summer peak load conditions. Different colors are assigned different price ranges. In the figure, blue signifies an area where nodal prices are $45/MWh or less, green signifies areas with approximately $50/MWh nodal prices, and red signifies prices of $55/MWh or more. This type of price visualization technique assists in identifying load (red zones) or generation pockets (blue zones), as well as the congestion expected to occur within the region (spanning the red and blue zones).
Figure 6 shows the distribution in nodal prices in ERCOT for the peak hour in 2008. The figure also shows that wide distribution in nodal prices develops from locational differences inside ERCOT. These locational differences are driven by congestion. Fig. 6 reveals prices much lower and much higher than the ERCOT-wide average price. Indeed, it is the locational price signal that is intended to provide market participants better information to use in managing operational and investment-related decisions affecting their asset portfolios.
It is clear from this figure that there are winners and losers, depending on location and whether injecting power into the grid (i.e., a generator) or removing power from it (i.e., a load-serving entity). Even within a single utility boundary, the variance in nodal prices can be quite high.
During the past three years, regulators and stakeholders in Texas have been heavily involved in developing the design elements for the Texas Nodal Market (TNM), as originally envisioned by the PUCT in 2003.5 As laid out by the PUCT, the TNM paradigm aims to reduce local congestion and market gaming opportunities, increase transparency, and make the siting of new resources and transmission facilities more efficient. Originally slated for Oct. 1, 2006, full implementation of the TNM has been delayed by the PUCT. At the same time, PUCT commissioners have confirmed their commitment to the nodal pricing model for ERCOT. Proposed implementation dates range from Jan. 1, 2008 to Oct. 1, 2009. Recent PUCT deliberations on the market design referred to July 2009 as a more realistic date. The PUCT recently has approved the TNM protocols. Further, ERCOT and stakeholders have formed a stakeholder Transition Plan Task Force accountable for reviewing and approving business requirements and design components related to the transition to nodal pricing.
The Lone Star State is famous for its bravado and self confidence. The performance of its competitive energy markets gives Texas bragging rights that others envy. Now Texas is turning its focus to the next stage of the power business cycle—buildup. If announcements like TXU’s coal-plant expansion are any indication, it’s going to be a fascinating ride into the future.
1. On July 17, 2006, ERCOT set a new record peak load of 62,396 MW, exceeding the previous record demand by 3.5 percent.
2. PUCT Project Number 24255: Rulemaking Concerning Planning Reserve Margin Requirements.
3. Senate Bill 408.
4. This continues to be true despite the fact that higher natural-gas prices have provided improved on-peak spark spreads for new, highly efficient gas-fired generation.
5. Substantive Rule 25.501 (Project 26376: Rulemaking proceeding on wholesale market design issue in ERCOT).