Winds Of Change In Texas
April 1, 2003
By Courtney Barry
Rising gas prices spark a rush to wind farms, straining grid capacity and raising larger issues about market design.
When the Public Utility Commission of Texas (PUCT) was drafting rules to encourage the use of renewable energy, it took pains to guard against the chance that power producers would fail to reach the state's target of 400 megawatts (MW) in installed new renewable generation capacity by Jan. 1, 2002. The commission needn't have worried.
In reality, the opposite happened. A spike in natural gas prices starting in the fall of 2000 helped launch a virtual explosion of wind farms in Texas in 2001, as power producers discovered that wind power could serve as a hedge in the fuel mix.
Yet this embarrassment of riches came with its own problems. Lacking the sorts of locational price signals common in PJM, New York, and Eastern electricity markets, builders had constructed nearly 1,000 MW of new wind capacity in West Texas, on the wrong side of a 500-MW transmission constraint in the Pecos River area. That left wind plants partially stranded, lacking full access to load centers farther east.1
As one legislative aide said last December, it might be easier just to move Dallas out west to the desert, than to move all those windmills.
All this new wind power created transmission congestion in the western part of the state, and the costs for clearing that congestion-now being uplifted to load-are estimated at $20 million per year. Why did this wind boom catch regulators by surprise? And why did power producers build in the "wrong" place? Some have wondered (including the PUCT) whether the problem might lie with the wholesale market design in the Electric Reliability Council of Texas (ERCOT), which operates the grid in most of the state and that has relied heretofore on a California-style zonal method for clearing congestion.
Indeed, ERCOT's zonal model appeared to have created the same pattern of phantom local congestion as seen in California. Insiders saw happening in Texas the same infamous "Dec game" as occurred in California, which allowed bidders to schedule resources in ways known to create congestion and then to submit decremental bids to the ISO to accept lucrative payments to withhold energy to relieve that same congestion.
Yet it may prove difficult to reverse ERCOT's market design and move to an East Coast model. While power producers in Texas likely would welcome the change (they already understand the PJM market), a shift might force retail suppliers and load-serving entities to spend money to remake software tailored to the ERCOT model.
To fix things, the PUCT's Market Oversight Division (MOD) appears to have embraced a third alternative for managing congestion-based neither on the old ERCOT zonal model, nor on PJM's bid-based and security-constrained nodal model, which features locational marginal pricing (LMP) with prices calculated after the fact. The middle way that the MOD has proposed for Texas would seek to relieve congestion through a system of flow gates and through a purely physical optimization of grid use. It would control congestion by attempting to control grid use directly, rather than indirectly, through incentive pricing for generation, as occurs under LMP. In this way, the MOD method might avoid ex-post pricing and appease those planners who contend that LMP tells producers where to build plants, but doesn't help grid operators decide where to build new lines.
Industry reps say changes at ERCOT could well influence events elsewhere, as policy-makers work to fashion new market designs in California and the Midwest.
Back in Washington, D.C., the Federal Energy Regulatory Commission (FERC) toils over its imperiled standard market design (SMD), even as wind developers in West Texas must grapple with a threatened sunset for the generous $18/MWh federal tax credit for wind energy.
To qualify under the current plan, wind developers must have new turbines in place by the end of this year.
Unexpected Glitches
In one sense, it is the very success of wind energy as an adaptable addition to the generation fuel mix that lies behind the apparent failure of the ERCOT design and the Texas grid to keep up to date with prices and markets.
It can take only six months to build wind generators, yet an estimated three to seven years to build transmission lines, including many variables outside of construction.
"How quickly can we get transmission built?" asks Bill Bojorquez, ERCOT's director of transmission services. "We are trying to find ways to deal with issues between now and the time that the line is built." But in addressing wind issues, the question becomes, "How do we accommodate as much of the wind resources that are now there within the limited transmission in a fair and equitable manner to both providers of wind generators and consumers?"
To come to grips with problems posed by wind developers in West Texas, the PUC opened a separate investigation last April to study ERCOT's wholesale market design.2 The PUC entertained proposals to establish a specific area, the Competitive Wind Power Area (CWPA), so that utilities might build transmission there and recover costs without fear of stranded investment.
Meanwhile, wind power generators only can wait for new policy to emerge. Consider Florida Power & Light (FPL), the largest owner and operator of wind generators in the state, with roughly 600 MW near McCamey, Texas. FPL's Beth Garza, director of market affairs, explains that generators are confronted with the uncertainties surrounding transmission constraints.
"It's the fact that we are seemingly powerless to mitigate the effects on us, and we really don't have any way to get the attention of the transmission providers, other than yelling and screaming and making a nuisance of ourselves," she says.
"Particularly for new projects, it's the uncertainty around the curtailments we may be facing that really makes it hard to commit financing for a project."
Then there are the cost recovery issues. Under PUCT regulations, transmission service providers charge service rates that include costs of facilities that are "used and useful." Yet companies that want to expand the grid can only project future need, not knowing what growth will bring.
"It's the old chicken and egg question," says Brian Almon, director of engineering for the PUCT. "There is a question in our mind whether we can certify a line for future need. And then the providers have the question, 'Should we build for 2,000 MW, maybe even 3,000 MW? What if it [the need] doesn't come?'"
A related problem is the potential time lost in getting interconnect agreements, as Stuart Nelson, manager of asset development for transmission service provider, the Lower Colorado River Authority (LCRA), explains.
"The problem that we have is that we cannot start on a project until a generator signs an interconnect agreement. We actually can't even start on the studies. If they sign an interconnect agreement, we start studies which can take anywhere from three months to a year," he says, and those are based on typical ERCOT schedules. "Even on relatively minor transmission lines, the project can take anywhere from three to five years from when you sign the interconnect agreement."
As for cost, Nelson says, "The most realistic risk that we have is that the project stops or goes away while we're in the certification process, in the first year. If it's certified and we start it, we're talking about $100 million projects, you could be potentially stranded for the total cost of the project. Obviously that is a risk that we or another transmission provider could not accept."
These uncertainties surrounding construction and other timely factors are exactly what frustrate wind generators. Discussions over transmission became rather heated at a West Texas Region Planning Group Meeting held at ERCOT in late January when FPL's Garza exclaimed, "If you don't build it, we won't come."
Here again, wind power developers simply have their hands tied until transmission constraints get cleared up; meanwhile, highly sought after investor money is put on hold.
Who Foots the Bill?
Texas regulators also must worry about the region's socialized or "uplifted" costs to relieve transmission congestion.
In a memo3 addressing local congestion problems as documented in a separate case at the PUCT to examine wholesale market design, Eric Schubert of the PUCT's MOD staff notes, "At present, ERCOT reimburses generators for lost profits for undeliverable energy scheduled across a local constraint."
In other words, ERCOT actually asks that the generator should withhold output to save room on the transmission system. The ERCOT protocol is known as "OOME," for Out of Merit Order Energy. "OOME down" is the term used to denote a decremental action when generators are asked not to generate.4 Who pays OOME downs? A customer in Austin, for example, helps pay wind generators in West Texas, not to generate power needed by the Dallas metro area.
Moreover, Qualified Scheduling Entities (QSEs) had been getting paid market value when they were OOME-ed down, but the wind generators did not recover the Production Tax Credit's portion of their revenue or receive renewable energy credits (RECs). Last fall, ERCOT approved a protocol revision allowing a QSE to file claims with ERCOT to receive payments covering the actual costs of providing service.
PUCT commissioners and staff want to change that. As noted in a staff memo, "The current system of payment to generators to relieve local congestion is very generous and does not provide the right incentives for generators to provide deliverable energy." The staff noted inefficiencies "because the unhedged cost of replacing the undeliverable energy to the other side of a local constraint inflates the cost of deliverable energy in ERCOT."
Last summer the commission established the market design rulemaking proceeding to address these issues. In January, Commissioner Brett Perlman asked for comments to address questions of whether ERCOT should change its congestion management model, and if so, to which type. Many parties, including the Coalition of ERCOT Market Participants (a group including TXU, LCRA, and CenterPoint Energy), are against radical changes to the present ERCOT model. As LCRA indicated in its response to the questions posed, "The viability of ERCOT's current model is demonstrated by ERCOT's performance in comparison to other markets. There have been more retail switches in ERCOT than other markets, ERCOT has a strong reserve margin, and wholesale prices are near marginal cost. All of these indicate a healthy market."
The commission's staff, working with consultants from the University of California, Berkeley (led by noted market expert Schmuel Oren), has now developed what some call a "nodal when you need it" proposal that would assign local congestion to generators deemed responsible for causing the congestion.5 (See Sidebar, "Nodal When You Need It: A Middle Way for Market Design.")
The MOD memo noted "a flaw in the ERCOT market design whereby market participants could engage in the 'DEC game'-that is, when market participants can schedule resources in such a way to create congestion and profit from the relief of that congestion." Citing West Coast problems, they added, "Local congestion rose dramatically in California years after a zonal model was implemented, so local congestion costs in ERCOT that are already substantial could dramatically increase in the future if not corrected now."6 MOD's proposal also suggested that their model could later segue into LMP, a move that prompted a lot of questions and was seen as rather utopian by some industry representatives.
The Zonal ERCOT Model, aka ZEN, supported by LCRA and South Texas Electric Cooperative, proposes to transfer ERCOT's market to a more "granular" market. Currently, the ERCOT market design is actually Zonal ERCOT Nodal, but without unit-specific bidding. ZEN eliminates portfolio bidding and uses unit-specific bidding.7 Also, the debatable day-ahead market could be incorporated into the current Zonal Design without LMP.
Then there's the LMP-based-on-PJM model, which is more granular and results in clearer price signals (notably favored by PUC Chair Rebecca Klein) so that generators and transmission actually site in better places. Notably, PJM's model is being looked at by FERC for its overall SMD design.
Evolution, not Revolution
Some argued it was simply premature to change ERCOT from zonal management of transmission congestion to a method based on nodal LMP. Citing extreme costs to ERCOT, wholesale market participants, and, ultimately, retail customers, the Coalition of Market Participants says it is "essential and mandated by public interest considerations" for the commission to "subject the implementation of nodal LMP to a rigorous and demonstrable cost/benefit evaluation."
"Our concern was with a tremendous cost with no offsetting benefits, and no benefit was explained to us that would benefit customers," says Jerry Ward, ERCOT market and regulatory director for TXU in Dallas. In its comments, TXU also noted that "retail competition is succeeding in ERCOT" while "struggling in the PJM states."
Texas generators' ties with PJM are among the many influences upholding the PJM model, a member of the coalition says. "They understand the rules of PJM. … But it's not going to cost them much to redesign the market. … The people that have to pay for the new systems are generally the load side."
As all these design options were being deliberated, Commissioner Perlman made it clear that a "forklift upgrade"8 was not the goal. Rather, it should be the development of a transition plan toward more granular pricing, which could go as far as a completely nodal system, or a system of trading hubs, similar to the way gas is traded. At that meeting, commission staff proposed going first to simultaneous market clearing (SMC)-a plan for zonal, but independent, bids from each generator as opposed to a fleet of generators.
"The SMC proposal is the first step because it allows the system operator to perform a security-constrained, economic dispatch, just like PJM," says Perlman.
Siding With PJM?
As far as modeling ERCOT after other models, TXU's Jerry Ward notes, "We were looking at the California market as we designed ours, and we were looking at what they did and what worked and what didn't work. We're differently situated. We're not connected to other states. We can control ours a little differently than they were able to." (Ward also chairs the working committee on congestion for ERCOT.)
But PJM has its own assessment of the model's influence. "The implications are the FERC SMD is really looking at a congestion management model and an RTO [regional transmission organization] model that's very similar to PJM in New York," says Andy Ott, executive director of market services for PJM. "They're saying, 'Hey, it's worked pretty well in these established markets; we'd like it to be similar everywhere.'"
From Ott's perspective, their model is attractive because, first, the areas adjacent to PJM will have a similar model, so it will be easier to coordinate power operations with them. Second, from a user point of view, everyone using the same model makes more sense economically because of the uniform or standardized software, he says.
"The actual constraints you impose to power operations are going to vary by region. … In the Northeast we're going to have different types of operating characteristics than they would in either Texas or the Midwest," Ott says. "I think people don't understand that you can have different operating criteria but really the same financial market overlay."
Influencing the Midwest
Meanwhile, in the Midwest, the Midwest ISO (MISO) is eyeing possible changes at ERCOT for several reasons. One has to do with the planned merger of MISO with Southwest Power Pool (SPP).
Carl Monroe, vice president of operations with SPP, and soon to be vice president of market operations for the merged company, notes that in the Texas panhandle, it is SPP that now provides RTO-type functions. Eventually, he explains, that role will be filled by the company created by the merger of SPP and MISO. "The transmission owners and utilities are expected to join that resulting company," he adds.
But more importantly, as Monroe explains, Texas is now served by two different interconnections, the ERCOT interconnection and the Eastern Interconnection.
"There are only two ties between those," he adds, "and they're both back-to-back DC ties, so that the effect on Texas if ERCOT changes its method would be how those DC ties are treated and coordinated with the two markets."
"Now from the PUCT perspective," Monroe says, "they might want similarities between the two markets for reasons to have Texas treated the same way with the two markets, but from ERCOT's perspective, any interaction with SPP presently and with MISO in the future-it's not necessary that those be the same."
Monroe adds, "The main concern for the Texas utilities and MISO is in making changes that would impose requirements on the Texas utilities that they may not be able to fulfill being a part of a FERC-regulated RTO."
Adjacent to MISO, the California ISO (CAISO) has been going through its own metamorphosis.
"We're changing our design to be in concert with standard market design and to have more flavor of what the Eastern ISOs-specifically New York-have," says Ziad Alaywan, CAISO's director of market operations.
Addressing California's notorious "phantom congestion," or gaming, which also recently became a concern for Texas, Alaywan says, "We have made some changes to fix some of the gaming, or what people thought was gaming" as a result of Enron and others.
"There are a lot of similarities between the Texas market structure and California's," notes Alaywan. "There's the zonal approach that Texas adopted-the notion that congestion is separate from a forward energy market. … We don't have a day-ahead energy market. We are going to have one in about a year."
He adds, "Texas deals with congestion just exactly the same way we deal with congestion here in California. We're changing that. The changes are to adopt the New York ISO model in terms of congestion and in terms of a forward energy market because we think there's some problem with it."
So will there be drastic changes to ERCOT? Word on the street is that ERCOT eventually will lean toward an LMP-PJM model. Meanwhile, tension runs high as other national decisions concerning SMD also ride in the wake of any ERCOT decision. With all the overriding issues and short timelines, both statewide and national, the situation in Texas could be akin to "changing the tires on a moving car," as one ERCOT consultant was overheard saying at a PUC open meeting.
Courtney Barry, a writer in Austin, Texas, formerly worked for the Public Utility Commission of Texas. She has also written on technology and business issues for The New York Times.
Endnotes
- See Rulemaking Proceeding on Wholesale Market Design Issues in ERCOT, Tex. PUC Project No. 26376, memorandum of Eric S. Schubert, Market Oversight Division, p. 12, filed Sept. 6, 2002. (Memo was filed also and made part of record in FERC's investigation of wholesale standard market design, see FERC Docket No. RM01-12-000, filed Nov. 15, 2002).
According to ERCOT, West Texas has about 1,700 MW of exportable generation and a transmission transfer capability of only 1,100 to 1,300 MW. The potential for exportable generation in the area can grow to 3,700 to 5,200 MW and the transfer capacity can increase to 1,800 to 2,300 MW.
- See Project No. 25819, Transmission Constraints Affecting West Texas Wind Power Generators.
- See Rulemaking Proceeding on Wholesale Market Design Issues in ERCOT, Tex. PUC Project No. 26376, memorandum of Eric S. Schubert, Market Oversight Division, p. 12, filed Sept. 6, 2002. (Memo was filed also and made part of record in FERC's investigation of wholesale standard market design, see FERC Docket No. RM01-12-000, filed Nov. 15, 2002).
- For more on OOME, go to http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/26376_19_364690.PDF pp. 3-4.
- See: http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/26376_19_364690.PDFwww.puc.state.tx.us , pp. 17-18 (for MOD's proposal see Project No. number 26376, filing no. 4, dated 08/23/02.)
- http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/26376_19_364690.PDF pp.17-18.
- See www.puc.state.tx.us, Project No. 26376, LCRA's Response to MOD's Jan. 21, 2003 questions, filing no. 90 or http://www.puc.state.tx.us/interchange/index.cfm.
- Defined as an upgrade to a computer network or other electronic system that requires a massive hardware investment. (See "Manufacturers of profitable PBX systems, notorious for requiring forklift upgrades and heavy maintenance fees, need a new five-year plan: Call it survival," Ken Phillips, "Sphericall 1.0 Dissolves PBXes Into the LAN/WAN," PC Week, May 5, 1997).
Nodal When You Need It: A Middle Way for Market Design
How the Texas PUC would remake ERCOT's market design, but not with a PJM-style regime.
The Problem:
- Zonal Methods Fail. Zonal prices do not reflect the price differentials of local congested areas within a zone. The location of line congestion will change over time as supply and demand conditions change. (Loads acting as a resource will have an increasing presence in ERCOT over time.) In addition, the current market design fails to send locational price signals. An immediate consequence of this failure is that almost 1,000 MW of wind power has been built or announced locating behind a 400-MW transmission constraint in the Rio Pecos area in West Texas. These poor siting decisions will lead to tens of millions of dollars of uplifted energy charges.
- New Zones Not Practical. Rezoning in ERCOT is done once a year through the ERCOT stakeholder process. Rezoning is more an art than science that is subject to non-market influences. A facet of the current zonal model not discussed in ecoomic theory is the inertia to maintain existing zones. During the summer of 2002 stakeholders expressed a strong desire to maintain current zonal boundaries because it would simplify their commercial contracts.
- ERCOT Pays the Bill. Inefficiencies in the pricing of local grid congestion costs have made the current zonal model in ERCOT unsustainable. ERCOT has already spent $90 million relieving local congestion in the first year of the ERCOT market.
Alternative Solutions:
- Restrict Hookups. Some stakeholders have suggested an administrative solution to the problem of wind farms piling into a congested area. ERCOT would refuse interconnection for certain facilities based on a judgment of how congested a local line might become.
- Locational Marginal Pricing. Implementing LMP in a market with retail choice raises some issues that other RTOs in the country are still addressing. Likewise, the form of LMP that FERC's SMD eventually will adopt is unclear.
- Direct Assignment. Directly assigning local congestion fees would be significantly less costly and time consuming than implementing LMP in ERCOT: (a) $2 million vs. $25 million to $40 million for LMP; and (b) six to eight months vs. a minimum of 24 to 30 months for LMP. (These are estimates only.) ERCOT has reviewed MOD's proposal to assign local congestion fees and found the proposal to be technically feasible.
The Proposed Method:
- Elements. MOD's proposal uses a mathematical optimization model consisting of: (1) an objective function: (2) resources available for redispatch; and (3) operational constraints.
- Optimal Dispatch. Optimizing produces shadow prices that are associated with each transmission constraint. These shadow prices reflect the marginal value of local transmission resources-i.e., how much congestion costs could be reduced by adding one more megawatt of grid capacity on the constrained element.
- Congestion Fees. Generators in a zone should be assigned a congestion fee (or payment) that equals the shadow prices on the congested local elements applied to the relative flow that they induce on these elements. -B.W.R.
Source: Eric S. Schubert, Market Oversight Division, Tex. PUC, Memorandum filed Sept. 6, 2002, Tex. PUC Project No. 26367. Also filed and made part of record in FERC (SMD) Docket No. RM01-12-000, filed Nov. 15, 2002.
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