Power System Planning:
Who gets paid (and how much) for backing up the system?
Ed Krapels-the electric industry consultant from Boston who helped dream up the initial idea of a monster, undersea direct-current cable (the Neptune project) to bring cheap Canadian power south to the Eastern Seaboard of the United States-thinks he knows now why the merchant transmission business is in the toilet."Independent transmission projects," he says, "need to be paid for their services to the capacity market."
Krapels believes that private-grid developers need the same incentives that regulators in the Northeast have OK'd for power plants. Some plans would pay financial transmission rights (FTRs) in exchange for participant funding by grid investors, but Krapels says that's not enough."Confining transmission projects to FTR payments," he explains, "is like confining generators to energy-only payments."
These words-from a press release that Krapels circulated by e-mail in early May through his firm, Energy Security Analysis Inc. (ESAI), of Wakefield, Massachusetts-speak volumes on what's happening in today's power industry, and on what the independent system operators (ISOs) and regional transmission organizations (RTOs) are trying to achieve, not only for merchant-grid projects but for merchant generation and system reliability.
But first, some background.
In recent installments of this column, we have reported on moves at the RTOs to create incentives for building new power plants and to ensure adequate long-term supplies of electric generating capacity. In large part, they have chosen to create spot markets for capacity rights. In short, the RTOs decide what utilities ought to be willing to pay to acquire rights to installed capacity (hence the term). Then they force the utilities to buy it. The price, however, is pure fiction. The RTOs set the price by reference to the total cost profile for a typical but hypothetical single-cycle gas combustion turbine power plant-, fixed and operating costs, interest rates and financing, fuel, labor, maintenance, heat rate and efficiency, site preparation, insurance, property taxes, and all the rest. Add in an estimate of revenues (likely sales of energy and ancillary services, based on projected prices), and you have a tentative figure for what utilities ought to be willing to pay for an incremental kilowatt.
Some ICAP plans take account of local transmission constraints and differing degrees of deliverability to individual nodes on the grid, and so are known as locational capacity markets, or LICAP. They employ complicated "demand curves" to plot a market price for capacity that varies over time as a function of regional supply needs ().
These LICAP regimes apply in regions where utilities have divested themselves of generation and have ceded control of transmission lines to the RTOs. Importantly, they allow merchant generators to lay claim to two independent revenue streams: (1) energy sales revenues, dependent on current prices in spot markets or bilateral contracts; and (2) the contributions to electric reliability, as measured by capacity value and paid through ICAP programs at the RTOs.
Now let's return to Krapels and why merchant-grid projects are foundering."If an AC transmission project could reduce New York City's locational capacity requirement by 10 percent," he notes, "the annual savings could be as high as $25 million."
But that's not the way things work today. In the typical case, a merchant transmission line (an "economic" grid addition, not strictly needed for reliability) would not get paid for its capacity value under current RTO regimes for transmission planning and expansion.
In fact, the Krapels theory runs clearly afoul of a basic tenet of rate making at the Federal Energy Regulatory Commission. FERC insists that transmission projects qualify only for "and/or" pricing. In other words, transmission can earn a cost-based return on investment as a compensation for contribution to the public service, or it can earn a competitive profit on the opportunity cost of power, but not both.
Thus, under PJM's RTEP plan for regional transmission expansion () or the New York ISO's CRP process for comprehensive reliability planning (approved at FERC late last year) merchant transmission doesn't receive a public-sector payment. Instead, any grid expansion need that cannot be solved by a purely market-based solution is thrown back into the realm of central planning. The planned solution (as devised by RTO committees, utility planners, or state regulators) then collects a guaranteed return under RTO tariffs or a commission-regulated rate.
That's why, as Krapels sees it, today's large-scale AC transmission projects are done only by traditional load-serving utilities and financed by traditional utility revenue streams that compensate utilities for creating system-wide benefits-the very thing that is denied to merchant grid developers.
Maybe Krapels has hit on something. In short, he implies that all system assets, whether generation, transmission, or other-and however financed and owned-should earn some revenues based on economics (the competitive market value of the energy product), and some revenues on contribution to reliability (capacity and system benefits).
FERC and the RTOs largely agree with Krapels on the generation side, where the ICAP plans have gained a grudging acceptance. Yet a big problem remains in converting theory to practice. The projected costs of paying these capacity credits to power producers has climbed to astronomical levels, in part because a key element is missing: consumer rights.
Unlike the traditional rate case or resource planning docket at the state PUC, the RTO ICAP process carries with it no explicit internal requirement that the final number must be "just and reasonable" (J&R), as is required of PUCs in setting retail electric rates. FERC can review the RTO findings, but cross-examination of witnesses and other features are missing from the RTO process, which looks very much like a virtual rate case but without due-process guarantees that are second-nature at the PUC.
In an interesting twist, some opponents of the New York ISO's CRP proposal had complained about too little of a federal role in the regional planning process. They had faulted the ISO's plan to delegate reliability authority to the state PUC if no market solution could be found to solve a problem with grid operations (congestion, constraints, load pockets, etc.), calling it "unlawful." Even the PJM RTO had said it was concerned that the state PUC's expansive role in the planning process could jeopardize the independence of the ISO.
Yet, in its order approving the plan, FERC itself agreed to take a backseat, and saw the plan as an opportunity to "dovetail our regulation" in order to work closely with state officials.
As FERC explained, the footprint of the New York ISO is contiguous with the state of New York, and so the state PUC was "singularly suited" to resolving disputes concerning the ISO's regional needs assessment and final determinations in the CRP process. ().
Moreover, it appears that FERC does not enjoy as much authority over reliability as some might think. Thus, to fall back on the work of the state PUC might actually make sense.
Nearly two years ago, testifying before a U.S. Senate Subcommittee, FERC Chairman Pat Wood III stated: "The explicit authorities granted to the commission in the area of reliability are very limited."
In fact, according to the New York ISO, a key facet of responsibility for reliability of the bulk power system should reside, and has always resided, with state regulators. FERC, says the ISO, can claim explicit statutory authority over reliability only to: (1) order interstate service upon complaint by a state PUC; (2) ascertain whether certain interstate interconnections are physically reliable; or (3) request reports or studies by reliability councils or other appropriate agencies. ()
Thus it is not everywhere that FERC and the RTOs hold sway. In California, for instance, the ISO (Cal-ISO) has not adopted a market-based ICAP program, nor does it intend to. Instead, it has imposed a must-offer obligation (MOO) requirement to force owners of electric generating capacity to make it available for sale in real time, and has decided on a strategic basis to rely heavily on state PUC programs to achieve regional reliability.
By turning away from an ICAP regime and embracing a planned solution managed by the PUC, the California ISO would return the reliability process back to the state. Once there, regulators would fix reserve requirements and their attendant costs under the standard of just and reasonable rates.
The jury was still out at this writing on how well the California compromise would work. The California PUC is set to issue a final order by the end of June in its rulemaking on resource adequacy. That timeline, in turn, has prompted Cal-ISO, hard at work in its market redesign, to wait a bit before proposing its next iteration of tariff language on how its new integrated forward market (IFM) will work. But we do know this: Cal-ISO's comments on the PUC plan, submitted through the winter and early spring, reveal serious concerns over temporal and locational factors. To translate, the PUC might find it a simple matter to set an overall planning reserve margin for each utility. But what mechanisms would ensure deliverability-that reserves would be available at the hours required and at all constrained locations? ()
Nevertheless, by shifting oversight on reliability from the grid operator to the PUC, the California plan would achieve the one thing that FERC and NERC (the North American Electric Reliability Council) have been seeking for so many years but without success-a reliability standard backed up by force of law.
New York: A Rate Case?
In regions that have adopted ICAP plans, the degree of complexity of analysis of generating costs can take your breath away. In the New York case, the full detail is outlined in a study presented in August of last year by the Boston consulting firm of Levitan & Associates. Consider, for example, only a very small part of the analysis.
The Levitan Study (the ISO's main case) would assume construction in Long Island or New York City of two, simple-cycle LM6000 Sprint aeroderivative gas turbine units, with a 96-MW capacity rating and heat rate of 9,739 Btu/kWh (at an ambient temperature of 59 degrees F). But for the rest of the state, either the 2xLM6000 or a pair of industrial frame 7FA turbines would be chosen. That's because, due to economies of scale, the 2xLM6000 plant would be 17 percent more expensive than the 2x7FA plant if operated in the rest-of-state zone. However, the LM6000 unit would be better suited to simple-cycle operation, as it can achieve full load operation in 10 minutes (allowing for higher emissions prior to operation of the selective catalytic reduction system). By contrast, the 7FA turbine would take longer to achieve full load and would be more commonly used in combined-cycle operation. In either case, financing would incorporate assumptions of a 3 percent inflation rate, plus 5 percent interest for construction debt, 7.5 percent over 20 years for the permanent debt term (the plant's useful life), a debt/equity ratio of 50/50, and an after-tax equity rate of return of 12.5 percent.
This level of detail gives power-plant developers lots of targets to shoot at in taking aim at the final ICAP demand curve and set of prices. And so, in the New York case, the ISO had complained that the developers, by their detailed protests over specific cost and operating characteristics of particular plant models, were "trying to turn this proceeding into a gas turbine rate case."
The ISO said the plant developers were attempting to steer the ISO ICAP process "in accordance with rate-making principles" to produce rates that would satisfy a traditional "just and reasonable" test. But the ISO bristled at this notion. "ICAP payments," it argued, "are not statutory entitlements akin to classic just and reasonable rates."
To defend its position, the ISO had cited the case of (. 2002), which puts down the notion that an RTO ICAP hearing is a virtual gen plant rate case:"[The] ICAP charge is not of this ilk. Rather, it is a payment to suppliers over and above the amount they charge for power. …"If ICAP charges were abolished by FERC tomorrow, the sellers could object that FERC was behaving unreasonably … but not that they were deprived of a just and reasonable rate."
As the ISO saw it, the developers' claim of entitlement to a just and reasonable ICAP rate was nothing but an "abused slogan."
Interestingly enough, FERC made no comment at all about the "rate case issue," or any entitlement to just and reasonable rates, in its final order approving nearly all the ISO's proposed elements for various sets of ICAP demand curves. (.)
New England: High Costs
The lack of state PUC participation and J&R rate protection stands out clearly in the case to set minimum requirements for installed capacity for utilities and load-serving entities (LSEs) in New England for the 2005-2006 power year, which was still pending before FERC in early May. This requirement, known in New England as OC (Objective Capability), incorporates a 12 percent reserve margin above the nominal load requirement. But while that determination would appear relatively straightforward at first glance, the case in New England has brought a stern admonishment from utilities, state PUCs, and attorneys general from across the New England region. They claim the ISO has ignored stakeholder and consumer interests and has caved to political pressure within the NEPOOL participants' and reliability committees. And worse than that, they say the ISO has misunderstood its role and has usurped jurisdictional authority to set targets for resource adequacy that resides with the state PUCs. (.)
To set the capacity requirement, the New England ISO (ISO-NE) analyzes three key elements: (1) load forecasts; (2) unit availability (, how to estimate scope and likelihood of future plant outages); and (3) tie benefits (the projected ability to import power across the grid from other regions, including Canada). It is the second two factors, availability and tie benefits, that have come under fire.
One bone of contention concerns unit availability. The ISO has proposed to abandon the EFOR (Equivalent Forced Outage Rate) model, which calculated random unit failure without regard to whether a plant is running, in favor of EFORD (Equivalent Forced Outage Rate Demand), which focuses on outages that occur when a unit is needed for dispatch.
By all accounts, however, the primary difference between the ISO-NE's proposed OC target for 2005-06 and that already approved in prior years stems from its move to lower its estimate of tie-benefit capacity from 2,000 MW to 1,800 MW. As lawyer Stephen Teichler explains (representing NSTAR Electric & Gas), that is a very big deal:
"Although a 200-MW difference may sound insubstantial in relation to the over 30,000-MW OC value, [we] estimate that this 200-MW compromise would cost consumers approximately $1.4 billion over the next five years."
But what was this compromise?
As it turns out, the ISO had put it to a vote. When faced with a range of possible values for tie benefits, the Reliability Committee of NEPOOL (New England Power Pool) had voted 70.65 percent for 1,400 MW, 56.61 percent for 2,000 MW, and 80.12 percent for 1,800 MW. Do the math. Has resource planning become a beauty contest?
To the ISO, all this seems like sour grapes. It counters that a similar vote with similar results was taken for the prior power year of 2004/05, without much controversy. That proves, says the ISO, that current objections center not so much on the ISO's nominal calculation of the OC target, but more on the much higher dollar impact that will follow if the ISO follows through on its parallel proposal to adopt a still more costly LICAP market.
But the most serious charges come from the Connecticut Consumer Counsel and attorney general, and from PUCs in Vermont, Rhode Island, and New Hampshire (joined by utilities Conn. L&P and Northeast Utilities). They complain, essentially, of a lack of any rate-case-like process to reach a J&R finding:
"Because [the] ISO has ignored the cost of its proposed increase in IC Requirements … it has not provided sufficient information to determine precisely what those added costs will be under any LICAP demand curve being considered."
Their objections clearly highlight the difference between resource planning at the RTOs versus resource planning at the state PUCs.
California: A Better Way?
PJM, the nation's most influential RTO market, appears on the verge of joining New England with a locational market for ICAP. The PJM plan, known as the Reliability Pricing Model, originally was scheduled for launch this spring (the proposal, that is) but has since been delayed, at least up until the time of a PJM board meeting that was to have taken place in early May. However, PJM has vetted many details. For example, specific proposed demand curves for three different PJM pricing zones can be found on the PJM Web site. ()
Nevertheless, the real innovation may come from California, where Cal-ISO deliberately has omitted a classic ICAP model from its proposed MRTU ("Market Redesign and Technology Upgrade," proposed several years ago as the MD02 - Market Design 2002) model. Instead, Cal-ISO has proposed to achieve supply adequacy in two ways.
First, the ISO would offer an availability payment to certain generators under a construct known as RUC (Residual Unit Commitment). RUC is not a true market, however. Instead, after close and settlement of its proposed Day-Ahead auction, the ISO would "reserve" the right to call on certain resources in real-time, should supplies fall short.
Second, Cal-ISO would extend its real-time must-offer obligation (MOO) to the Day-Ahead market as a temporary stopgap, until the California PUC fully implements its proposed rule for establishing a resource adequacy requirement (RAR). In broad terms the RAR can be thought of as a state-mandated equivalent of New England's OC target. California's RAR target would impose a planning reserve margin of between 15 to 17 percent above nominal load requirements, to be phased in by utilities over several years.
Space does not permit a full description here of the CPUC plan, let alone the latest version of the Cal-ISO's MRTU, with its new, bid-based, security-constrained Day-Ahead settlement, and its Hour-Ahead preview of the real-time closing. For an overview of the origins of the Cal-ISO market design and the CPUC initiative, see "Market Design Still Eludes California," published in , March 2004. ()
Nevertheless, for this discussion, at least two key points stand out.
First, the Cal-ISO's peculiar RUC construct. Though it offers a payment for availability, RUC is not a product market. Rather, RUC is a sort of option-a call on generators that lets Cal-ISO hold the capacity in reserve, at the end of the Day-Ahead closing, as a hedge against a real-time supply deficiency. RUC is not designed as an incentive program to encourage gen plant construction over the long term. It is more like an insurance policy. It is a hedge against the specific risk of a shortage of energy (not capacity) in the short term. As Cal-ISO itself explains, the RUC availability payment "is essentially an up-front reservation payment for an energy service."
Second, the real capacity element lies with the PUC's enforceable RAR mandate. With the PUC worrying about the long-term outlook for generating resources, and the huge costs of the attempting to influence long-term investor behavior, the ISO is left free to manage short-term physical operations. (In fact, the Cal-ISO has raised key questions about how the PUC's RAR standard will not work in practice unless it is designed carefully to account for grid congestion, constraints, and load pockets, which can block delivery of energy or capacity. )
Overall, the California plan represents a experiment to meld the ISO's technical expertise with the PUC's political acumen.
In California at least, someone will be worrying about the cost of ensuring adequate resources, and whether we can afford it.
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"Independent transmission projects," he says, "need to be paid for their services to the capacity market."
"Confining transmission projects to FTR payments," he explains, "is like confining generators to energy-only payments."
"If an AC transmission project could reduce New York City's locational capacity requirement by 10 percent," he notes, "the annual savings could be as high as $25 million."
"[The] ICAP charge is not of this ilk. Rather, it is a payment to suppliers over and above the amount they charge for power. …
"If ICAP charges were abolished by FERC tomorrow, the sellers could object that FERC was behaving unreasonably … but not that they were deprived of a just and reasonable rate."