Can a single utility dispatch a regional grid system without a financial market?
Bruce W. Radford is editor-in-chief for Public Utilities Fortnightly.
As of Monday evening, Sept. 5, 2005, a week after Hurricane Katrina, Entergy was reporting 54 transmission lines and 46 substations still out of service. That meant nearly 459,000 customer outages—some 417,000 in Louisiana, plus 41,000 in Mississippi. By the next day, Entergy had told the U.S. Securities and Exchange Commission that earnings for the current and next year likely would suffer. Also, regulatory mechanisms might be modified to recover the cost of restoration.
Against this backdrop, it might seem premature or even gratuitous to review Entergy’s pending plan to create an “Independent Coordinator of Transmission” (ICT) to manage certain grid operations. Yet consider what happened four years ago after Hurricane Lili had inflicted damage (much less, of course) to the Entergy grid.
According to the Lafayette Utilities System (LUS), a small municipal electric system lying in the heart of Cajun country, Entergy effectively de-rated its 138-kV Richard Colonial Academy transmission line by 15 MVA when it chose to install a readily available but lower-rated capacity conductor in 2002 after the storm.
Today, Lafayette alleges that congestion on the R-C line has cost it at least $2 million over the past three years—no small sum for the city. It seems LUS lies in a load pocket, tied directly only to Entergy and Cleco Power LLC. Thus, LUS says that often it must ramp up its higher-cost Bonin plant, while ramping down the coal-fired and cheaper Rodemacher base-load unit, to accommodate output from the 1210-MW Arcadia plant, a merchant facility half-owned each by Calpine and Cleco. This situation occurs when Entergy (the reliability coordinator for the R-C line) declares TLRs (transmission loading relief), and asks the Southwest Power Pool (SPP, the coordinator next door) to tell LUS to redispatch.
In fact, LUS says Cleco has filed studies at the Federal Energy Regulatory Commission (FERC) that show “a complete absence” of import capability into the LUC control area during the winter months.
Lafayette argues, however, that if Entergy would give up its ICT plan and join the SPP RTO, then LUS could take transmission service directly from SPP under the RTO tariff. That would make Lafayette eligible to receive payment from SPP for the redispatch costs. Yet, though LUS is a “member” of SPP, it lacks a direct physical connection to SPP and thus cannot claim reimbursement. (See, Protest of Lafayette Utils., FERC Dkt. ER05-1065, filed Aug. 5, 2005.)
This anecdote marks just the tip of the iceberg. It shows in miniature why the ICT question is so important and so complicated. And it illustrates how, for years now, merchant generators and others have complained of difficulties in gaining access to the Entergy grid. They have cited irregularities in how Entergy analyzes, calculates, and allocates transmission capacity to third parties. FERC, in fact, has acknowledged this and from time to time has opened investigations and audits on Entergy’s grid operations, including models, assumptions and software, but now holds those efforts in abeyance, hoping that the ICT plan might resolve some problems. (For details, see Audit Report on Gen. Operating Limits, FERC Dkt. PA04-17, Dec. 17, 2004; 109 FERC ¶61,281, Dkt. No. EL05-22, Dec. 17, 2004; and Protest of Cottonwood Energy, pp. 7-8, appendix, FERC Dkt. No. ER05-1065, filed Aug. 5, 2005.)
Entergy, also, has not stood still. Though state regulators in the South have remained skeptical of FERC’s vision, Entergy has sought to comply. The company has pushed for grid reform, of one kind or another, for at least the last half-dozen years—if you start your count with the company’s initial attempt, back in 1999, to create a “Transco” (an independent free-standing transmission-only company), and then continue with the company’s more recent but ill-fated attempts, first with the Southwest Power Pool (SPP), and later with the SeTrans group, to form a regional transmission organization (RTO) with sufficient scope and configuration to pass muster under Order No. 2000.
A key factor is the sizeable portfolio of IPP capacity (17,500 MW owned by independent power producers) that blankets the Entergy footprint. If properly integrated in a least-cost dispatch, this cheaper merchant capacity might well displace a significant portion of Entergy’s older, less-efficient and costlier fleet, saving millions for ratepayers. Entergy’s own studies bear this out. Appearing for the Southeast Electricity Consumers Association (SeECA), consultant James Dauphinais (Brubaker & Associates) testified earlier this year that, “according to Entergy’s numbers,” the utility’s market purchases of gas-fired IPP generation saved $870 million for its ratepayers in 2002-2003. These savings, he said, greatly would exceed the value of transmission service credits that Entergy would owe to the IPPs, under current FERC policy, in exchange for grid network upgrades for which the IPPs had paid over the same period.
Overall, says Dauphinais, reports from Entergy point to a $30 million annual cost savings for ratepayers for each percentage-point decrease in use of the utility’s oil- and gas-fired generating units, in favor of IPPs. (See Affadavit of James Dauphinais, pp. 12-13, on behalf of protest of SeECA, FERC Dkt. No. EL05-52, filed Feb. 4, 2005.)
A Wait-and-See Attitude
Now comes Entergy with its immensely complex ICT grid plan, first proposed in April 2004 (FERC Dkt. No. ER05-699), and modified this past spring, after FERC ruled on its jurisdictional status. (See Dkt. No. EL05-52, March 22, 2005, 110 FERC ¶61,295, and FERC Dkt. ER05-1065, filed May 27, 2005.)
On the surface, the plan would create independent accountability for the transmission grid, as called for in FERC Order No. 2000, with special attention paid to planning and expansion. Will the model work? Can it improve grid access for IPPs and reduce energy costs for Entergy’s ratepayers?
On a positive note, Entergy’s ICT plan already has elicited copycat plans from Duke and Warren Buffett’s MidAmerican Energy, each filed at FERC on July 22. (See Duke Energy, Dkt. No. ER05-1236; MidAmerican Entergy, ER05-1235.) The attraction is obvious: any electric utility could create its own self-contained “lite” version of an RTO, more or less free of FERC oversight. Nevertheless, the Duke and Buffett plans as proposed stop way short of the incredibly complex regime that Entergy has offered up. For the true student of utility regulation, the Entergy plan is the one to watch.
Consider the delicate political compromise that defines ICT construct. Under Entergy’s vision, the ICT would retain just enough independence as a third-party grid monitor to allow Entergy to propose a radical new variant of participant funding to set prices for transmission access and expansion. (FERC policy permits participant funding only for “independent” grid system operators, such as RTOs.) However, the ICT’s independence would not extend so far as to strip Entergy of its status as the transmission service “provider.” And so the state regulators would not forfeit their coveted authority to oversee the “retail” transmission function—with assets and costs included in the retail rate base as a bundled adjunct to retail distribution service—so that PUCs can review the efficacy of grid investments.
For example, the ICT would run the Entergy OASIS node and grant and deny access to Entergy’s lines, but only by using Entergy’s own data, models, and calculations of available grid capacity. It could “observe” how Entergy calculates and allocates costs, credits, and hedge rights arising from grid congestion and redispatch, but only as a hired contractor, with the utility setting its budget. Many believe this budget dependence would lead the ICT to defer to Entergy, undermining its supposed independence. Also, the ICT would draft the “Base Plan” that dictates which upgrades are needed on the grid according to good utility practice to maintain reliability, but utility staffers would write up an alternative “Construction Plan,” meaning that Entergy could decide not to build the very projects that the ICT deems necessary.
This balancing act could give added leverage to state regulators—Alabama says it could mediate disputes between the ICT and the utility.
And if that were not enough, Entergy proposes for the ICT to re-examine and retroactively repudiate generation interconnection deals signed previously with IPPs, for those agreements lack Mobile-Sierra language to bar a unilateral contract modification. Thus, the ICT would conform older interconnection agreements with the new policy of participant funding for “supplemental” grid upgrades that go beyond what is needed in the ICT’s base plan to support reliability. The ICT would reclassify grid upgrades that were required to facilitate the interconnections, thus exempting the utility from some portion of the millions that Entergy would otherwise owe to reimburse IPP plant developers for footing the cost of those upgrades (to be paid, most likely, through credits against transmission service charges.)
This provision looks like a poison pill for FERC, since it appears to violate federal policy. However, Entergy admitted that without it, the costs of its overall ICT plan will outweigh all possible benefits for ratepayers in Louisiana. Commenting on the retail ICT case pending in Louisiana, consultant Stephen Baron (of J. Kennedy and Associates) raises serious doubts on whether this retroactive reclassification of costs—“the largest single source of benefit to Louisiana retail ratepayers from the ICT proposal”—would really save as much as Entergy predicts, since he reports that Entergy already has paid out $97 million in transmission service credits on prior network upgrades. (See Direct Testimony of Stephen Baron, La.P.S.C. Docket No. U-28155, filed Aug. 5, 2005.)
FERC views the ICT plan only as a two-year experiment, given that many details remain to be ironed out.
For her part, FERC Commissioner Nora Mead Brownell has voiced a wait-and-see attitude: “While I agree with my colleagues that the ICT proposal is a step forward, I remain skeptical primarily given my experiences with Entergy over the last few years. Promises have been made, promises have been broken.” (Docket EL05-52, concurring opinion, March 22, 2005, 110 FERC ¶61,295.)
A Physical Grid
To grasp the real import of Entergy’s plan—its implications for the rest of the utility industry—forget all those political debates on whether the ICT is truly “independent” of Entergy’s influence and control. Don’t worry whether FERC should permit individual utility companies to form their own quasi-RTOs, free from most federal regulation, in order to please recalcitrant state regulators. Rather, focus instead on the deeper question posed by the plan: Can Entergy create a regional grid system that relies solely on physical rights?
First, give credit to Entergy for its creativity. The ICT plan seeks to do much of what the other RTOs do. For example, the ICT provides for regional coordination of grid planning. Through its Weekly Procurement Process (WPP), a weekly solicitation of energy from IPP plants, Entergy’s plan would at last integrate IPP generation with utility-owned resources in a single, security constrained regional dispatch. Coupled with Entergy’s participant funding proposal (designed to encourage investments in new grid capacity), the WPP would allow Entergy to provide hedging rights against grid congestion as compensation to grid customers (such as IPPs) that fund supplemental grid upgrades.
At the same time, the ICT plan would offer one feature that other RTOs lack, and which FERC heretofore has not required: It would create and award transmission service rights as compensation and incentive for grid investments that boost grid capacity so as to facilitate additional long-term transmission service. Entergy offers this feature in recognition of the fact that grid investment is often “lumpy.” IPPs that fund grid upgrades to facilitate plant interconnections cannot always scale down their investments to the minimum level required by the facility in question.
Yet consider a very big question mark. Entergy’s plan would undertake all these tasks without financial rights. The plan fails to offer locational marginal pricing, whether nodal or zonal. No capacity market is present, such as ICAP or LICAP. The plan offers no true FTRs, as that term is commonly understood, since the congestion hedging rights and “lumpy” grid credits that it offers are tied to use only on the flowgates for which the upgrades were performed. That would make it difficult to trade these rights, a feature that FERC has insisted upon in its most recent orders.
Above all, the plan fails to provide any sort of regional market-clearing price, whether for energy, capacity, ancillary services, or short- or long-term reserves. Instead, the WWP solicitation pays suppliers as bid. There is no market to be found, whether hour-ahead, day-ahead, or real-time. But FERC in its guidance orders has said that is perfectly OK.
A Peculiar Auction
Perhaps the crucial hurdle lies in the “black box” nature of the WWP solicitation of energy offers from IPPs.
According to Entergy’s latest iteration, suppliers offering energy through the WWP protocol must include a number of cost elements in their weekly bids, including start-up costs, a heat rate, a gas price index, and a gas-basis adder. (See Application of Entergy Services, Inc., FERC Dkt. No. ER05-1065, cover letter p. 38, filed May 27, 2005.) However, the bids aren’t ranked by price, or any other standard protocol that Entergy has articulated precisely to potential bidders. Also, with a weekly settlement, instead of hourly, and with no contingent bidding (an second offer to sell to quantity Y to buyer B, if the first offer to sell to X to A falls through), merchants say they face much greater risk than in the typical RTO day-ahead auction.
According to consultant David DeRamus (Bates White LLC), testifying for Calpine, suppliers must submit offers containing some 19 parameters in all, but have no way of knowing how those parameters are ranked for the selection of the winning bids. That’s because, as Entergy’s Rick Smith, group president of utility operations, explained at the technical conference held in New Orleans, on Thursday afternoon, July 29, 2004, the company is looking to IPPs not so much for price, but for flexibility (in hours of operation, ramp times, and so forth), so as to mesh with dispatch of Entergy’s incumbent gen fleet:
“Now, Entergy’s units have high heat rates, that’s true,” says Smith, “but the ratio of their minimum block to their maximum capability is quite favorable and their ramp rates are favorable. It’s not saying that they can’t be beat by somebody else, but if you have a unit that has 200-MW minimum segment and a 500-MW maximum segment and a high ramp rate, and you have somebody else come in and say, I’ll bid you a 300-MW minimum and a 500-MW maximum, you don’t have the same flexibility.”
Thus, Entergy will dispatch resources to accommodate transmission service requests, but without a market price to compare the value of competing schedules.
Doubts still trouble the merchant gen community, as shown by this quote, taken from the same meeting, from Intergen Vice President Andy Shearer: “For instance, if I’m in PJM or I’m in New England, I know very well if I made it or not, because I get a price signal. … I offered my unit at $50 and the market is at $48. I was $2 off. Not exactly hard to figure out. … “I’m not saying that Entergy is doing it incorrectly. They may well be doing it precisely right. I just don’t know.”
Mississippi Commissioner Michael Callahan echoed that concern at a meeting held in Jackson, Miss., in August 2004, as retold by Calpine’s regional counsel John Bellinger: “You’ve got to give these guys some numbers, some target to shoot at so that they know where they stand, instead of … doing it in the dark every week.”