Six weeks ago, FERC opened a notice of inquiry to invite industry comments on whether wind, solar, and other intermittent energy sources face unfair obstacles in wholesale power markets. Now...
No Generator Left Behind
A new theory on capacity markets and the missing money.
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