A new theory on capacity markets and the missing money.
Bruce W. Radford is publisher of Public Utilities Fortnightly. Contact him at firstname.lastname@example.org.
On Wednesday May 7, the Federal Energy Regulatory Commission (FERC) will host a conference in Washington, D.C. that might prove extraordinary. The commission staff promises not only to review the forward capacity markets now operating in New England and PJM—each a story unto itself—but also to discuss a new rate-making theory that has come virtually out of nowhere and which proposes to help solve the notorious “missing money” problem (see sidebar, “I’ll Take the Blame.”)
This new theory, thought up essentially by one person (a utility lawyer, no less), seeks to harness recognized quirks in predictive human behavior to better define and manage the most important single financial risk in the electric industry today. That risk, present in all areas of the country where independent power producers are active, concerns the fixed costs (financing, construction, site permitting, etc.) of adding new generating capacity to the power grid. The risk remains pervasive because, for political reasons, the market operators at RTOs and ISOs (with exceptions in Texas and the Midwest) generally prevent peak-period energy prices from rising high enough above marginal operating costs for power-plant owners to recoup all or even a portion of their fixed costs.
The theory’s architect is attorney Donald J. Sipe (Preti, Flaherty, Beliveau & Pachios, Augusta, Maine), who has long represented the American Forest and Paper Association before the FERC.
Sipe is a perpetually curious student of behavioral economics. He delights in discovering the mysteries of markets. For example, why is it that a typical stock market investor will behave differently when offered twin chances to lose money or earn an equal gain, even if the risks are the same? How do economists explain such behavior? Can regulators apply this wisdom to regional capacity markets?
Armed with such quaint notions, Sipe developed an entirely new electric industry contract (an option, really) that he calls a “financial performance obligation” (FPO). He offers this construct as a superior method of pricing the fixed-cost risk.
Paying for Scarcity
For regulators, at least, the allure of capacity markets is easy to grasp. Without such a market or a separate capacity payment, plant owners would be forced to recover all fixed costs through the energy price. That’s the so-called “energy-only market,” now being tried in Texas (in ERCOT) and at the Midwest Independent System Operator (MISO). That suggests that regulators must allow scarcity pricing during shortage periods that reflects the value of lost load (VOLL).
An EO market means that the probability of lost load (LOLP) must equal the cost of building a new plant (the gross cost of new entry, or CONE) divided by VOLL. Assume a target LOLP of one day (24 hours) every ten years. Assume also that it costs about $72 per kilowatt-year to build a new plant that will operate on the margin in RTO markets (more than likely, an aero-derivative simple-cycle gas-fired combustion turbine). You’ll find that VOLL equals $72,000/megawatt-year divided by 2.4 hours, or $30,000 per MWh.
That’s the mathematical proof that, in an EO market, given today’s cost of building a new power plant, the wholesale spot energy price must be allowed periodically to climb as high as $30,000 to make generators whole. That’s the money that’s “missing.”
In reality, you would expect retail customers to step up and offer to curtail consumption, in exchange for a demand-response payment, long before retail prices hit $30/kWh. That’s why, in Texas, ERCOT plans to cap energy prices at $3,000/MWh in its EO market. In similar fashion, MISO’s new controversial ancillary services market seeks to cap scarcity prices at $3,500/MWh: a $1,000 energy-offer cap plus a maximum $2,500 adder for reserve shortages.
Back East, however, PJM’s reliability pricing model (RPM) has become mired in controversy. Citing high prices, buyers in the PJM’s RPM called on FERC in March to launch a full review. And even as this complaint was pending, PJM itself was proposing even higher rates. On February 6, though lacking stakeholder approval, PJM had proposed a 40 percent percent increase in the gross CONE value, from $74.11/kW-yr. to $105.41/kW-yr., for the upcoming base residual auction (May 5-9) for capacity deliverable June 2011 in the Southwest MAAC sector, covering Baltimore, Washington, D.C. and the surrounding suburbs. But FERC blocked that bid in early April in a terse opinion that left no doubt of its sentiment that RPM could be improved. (Docket No. ER08-516, April 4, 2008, 123 FERC ¶61,015.)
The key issue in PJM concerns a mathematical adjustment known as the “E&AS offset,” which represents revenue that power-plant owners can earn in the spot energy and ancillary services market. PJM subtracts these E&AS revenues from the estimated cost of building new gen plants, yielding a value known as “net CONE.” Relying on this estimated net CONE value, plus a target installed capacity quantity that includes a 16 percent reserve margin above peak load, PJM constructs an artificial downward-sloping demand curve. Capacity in the RPM clears at a price set three years ahead of actual physical delivery, at the intersection of this demand curve with a real-world supply curve constructed from actual producer bids (such bids can include demand-side resources, or even offers to build new transmission). PJM’s solution to avoid double recovery has come to be known as the ex ante method. The ex ante E&AS offset to calculate net CONE is needed to avoid reimbursing generators twice for the same missing money, which would happen by just adding a capacity payment on top of dollars already earned in the energy and ancillary services markets. (For more, see, “PJM’s Reliability Pricing Mechanism: Why It’s Needed and How It Works,” by John Chandley, Principal, LECG Consulting, March 2007, as attachment to Response of PJM Power Providers’ Group, FERC Docket No. ER05-1410, filed April 4, 2008.)
By contrast, New England’s forward capacity market (FCM) works differently—more like an RFP solicitation than a market. It features a descending clock auction, but not a pre-fixed demand curve, so there’s no pre-targeted clearing price pegged to the cost of new entry, nor even any need for the region to define a value for gross or net CONE. Yet the need remains to avoid double recoupment of the missing money, so the FCM contains a reconciliation step that is roughly parallel to the RPM construct, known in New England as the “ex post PER adjustment.” By this mechanism, ISO New England deducts peak energy revenues (revenues for sales of energy and ancillary services that exceed the marginal generator operating cost) from capacity payments paid to generators. The PER adjustment is in a way generic; the ISO first calculates the excess peak revenues that would be earned by a hypothetical prototype turbine unit with a given heat rate—a unit of middling fuel efficiency —and puts producers at risk if they cannot match that performance. In other words, producers know, before they bid into the FCM, that they have a chance to earn a windfall in the energy market, but that the ISO eventually may take that windfall away through the ex post PER adjustment. But they can minimize that risk by exceeding the target efficiency of the prototype unit.
The problem in PJM, meanwhile, is that while capacity prices are forward-looking, the ex ante E&AS offset is lagging—based on a three-year historic average of energy market revenues.
An exhaustive 85-page study prepared recently for the American Public Power Association presents evidence showing that producer revenues in PJM’s Energy and AS markets are rising steeply with every passing year—a trend not captured in RPM capacity prices. (See, “Raising the Stakes on Capacity Incentives: PJM’s Reliability Pricing Model,” James F. Wilson, LECG consulting, March 14, 2008) Given these forward price adders and lagging price offsets, calls have come for FERC intervention, led by the PJM RPM Buyers group, which includes state regulators and consumer advocates in Maryland, Ohio, New Jersey, Pennsylvania and D.C., plus the PJM Industrial Customer Coalition, the U.S. Dept. of Defense, and Donald Sipe’s American Forest & Paper Association, among many others. (See, RPM Buyers’ Motion for Technical Conference, FERC Docket No. ER05-1410, filed March 19, 2008.)
Of course, power-plant construction costs are rising dramatically. Also, PJM’s capacity market solicits new investment three years down the road, when costs will be higher still. Three months ago, on February 14, Cambridge Energy Research Associates released its latest IHS/CERA Power Capital Costs Index. The new PCCI showed that the cost of new power-plant construction in North American had risen 27 percent in 12 months, and 19 percent in the most recent six months, reaching a level 130 percent higher than in 2000. (See, http:energy.ihs.com/News/Press-Releases/ 2008.)
The oft-cited Handy Whitman Index suggests a similar trend: A 15 percent increase in gas turbine construction costs from 2006 to 2007. (See, “2008 Update of Cost of New Entry Combustion Turbine Power Plan Revenue Requirements,” Pasteris Energy, Inc., available as attachment to PJM’s proposed RPM revisions, FERC Docket No. ER08-516, filed Jan. 30, 2008.)
All these points fell on deaf ears at FERC, however. In its recent opinion denying PJM’s bid to boost its CONE value and shift clearing prices upwards in PJM’s RPM market, FERC showed no mercy:
“PJM and the stakeholders need to consider whether PJM’s proposed method of calculating CONE by using projected values, including inflation, creases a mismatch with the determination of energy and ancillary service revenues, which rely on a historic average of the past three years.”
A Short-term Fixation
Out West, the California Public Utilities Commission (CPUC) made news in January when it proposed two alternative models for resource adequacy and capacity procurement and asked for comments, after holding extensive workshops last August on a half dozen proposals, with exotic names like “PG&E Bilateral with Multi-year Forward.” (See, Staff Recommendations on Capacity Market Structure, January 2008, Cal.P.U.C. Dkt. R.05-12-013, at ftp://ftp.cpuc.ca.gov/puc/hottopics/1energy/ r0512013MarketStructure.pdf.)
Industry comments then came back on leap day, February 29, with many describing the CPUC staff proposals as inadequate. One staff proposal, relying on bilateral procurement to ensure enough new gen investment, essentially would maintain the status quo. The second, a modified CCM (centralized capacity market) was faulted as too vague. Many wondered why the staff had not simply recommended the precise model recommended by the California Forward Capacity Market Advocates (CFCMA), which was designed after New England’s FCM construct, but without the ex post PER adjustment, and which had been thoroughly explained and vetted in the August workshops. Why instead had the staff decided to propose a new, relatively unknown market model, which was ill defined and even less understood, and then asked for comments?
The CPUC staff believes that a bilateral capacity procurement scheme, falling entirely under state law jurisdiction, will do a better job of complying with state-imposed mandates for developing renewable energy. The CPUC also suggests that that a FERC-regulated and Eastern-style CCM, with a uniform single clearing price (rather than pay-as-bid) fails to satisfy least-cost principles, since all resources receive capacity payments keyed to newly constructed, high-cost combustion turbines operating on the margin.
The CPUC staff report echoes concerns expressed late last year by the CAISO Market Surveillance Committee. The MSC had urged the CPUC not to adopt a bid-based capacity market, and only make small refinements to the state’s current RA framework. (See, Opinion on Long-term Resource Adequacy under MRTU, Nov. 5, 2007.)
Also, the CPUC staff faults the CFCMA market proposal because it did not include an ex post PER adjustment, as seen in New England. The CFCMA group had said such an adjustment simply would raise clearing prices, since suppliers would respond by raising their bids to cover the risk that the ISO might dun their capacity payments to offset a possible energy market windfall.
California’s power producers for years have been complaining of a broken regime for resource adequacy, owing to faulty policies at both the CPUC and the California Independent System Operator (CAISO). That RA regime, they say, has long favored vertically integrated load-serving utilities, which can fall back on rate base to recover their missing money, while forcing merchant plants to shoulder the burden.
The CPUC’s RA program gives capacity credit to LSEs for certain demand-response resources and credits other resource contracts that the California Independent System Operator cannot easily call upon (without declaring a stage two emergency, which the CAISO does not like to do). So resources run short in real time, prompting CAISO to step in to remedy the problem by using various “backstop” programs. One such program is the RCST—reliability capacity services tariff—set to sunset on at the end of 2007, but which FERC has now revived. (See, FERC Docket EL08-20.) Another is the ICPM —interim capacity procurement mechanism—proposed by CAISO as a fill-in to replace the RCST until its new MRTU kicks in, with locational marginal pricing and financial congestion management, but which has been delayed indefinitely. (See, FERC Docket No. ER08-556, filed Feb. 8, 2008.)
In short, the CPUC’s RA rules tend excuse LSEs from reserving enough capacity, and then hit up the IPPs for the shortfall, but paying them an inadequate compensation equal only to their going forward avoidable costs; not a CONE-based rate. (Note: The CPUC is re-examining its RA regime in two new rulemakings: R.08-01-025, Feb. 4, 2008; R.08-02-007, Feb. 20, 2007.)
Overall, the IPPs say that compensation comes up short under CAISO’s RCST and ICPM plans, and should run more in line with estimates of new plant construction costs and CONE values that can be seen in a recent study conducted by the California Energy Commission. (See, “Comparative Costs of California Central Station Electricity Generation Technologies,” Final Staff Report, CEC-200-2007-011-SF, December 2007.)
The IOUs, of course, need not rely on RCST or ICPM payments. They can roll the entire plant cost into rate base in CPUC-sanctioned rates, by which they get a full, guaranteed recovery of all fixed costs, including return on capital. Thus, the IPPs argue that the current and honest capacity price exceeds their meager RCST payments or proposed ICPM compensation, represented clearly in the form of new gas turbine units constructed recently by the regulated, investor-owned electric utilities, such as Southern California Edison. (Note: SCE denies in FERC filings that certain of its recent turbine projects are truly representative of going construction costs, as it claims that it built the plants on a rush schedule to meet emergency needs. (For more on this issue, see Protest of Independent Energy Producers Asso., Affidavit of Joseph Cavicchi, FERC Docket No. ER08-556, filed Feb. 29, 2008.)
In fact, IPP complaints suggest that CAISO’s short-term backstop strategy actually may depress the energy market price, already heavily mitigated in California. As Constellation Energy and Mirant explained in their comments in the ICPM docket, “Unplanned-for operational issues that arise in the short term are not solved by procurement of more capacity; they are solved by procuring more energy.”