The Mid-Atlantic grid operator just won a court case to keep capacity performance rules that hurt clean energy. Will carbon pricing and market reforms help make up for it?
PJM, the grid operator responsible for delivering electricity to about 65 million customers from the mid-Atlantic coast to the Great Lakes, is working on ways to price carbon into its energy markets, and incorporate subsidized wind and solar power into its mix. It’s also projecting a future grid that’s stable despite a rise in wind, solar and demand-side energy flexibility — contrary to concerns expressed by Energy Secretary Rick Perry.
But for green energy advocates, none of that makes up for the negative effects of PJM’s Capacity Performance rules — and as of this week, those rules are sticking around for awhile.
On Tuesday, a three-judge panel of the D.C. Court of Appeals rejected challenges to the Federal Energy Regulatory Commission’s approval of new electricity market rules for PJM’s 13-state region. Known as capacity performance, these rules introduced year-round requirements, broken into winter and summer seasonal markets, to replace the summer-peaking-only market that’s been in place for decades.
PJM’s new year-round requirement was partly a response to the 2014 polar vortex, when record-cold temperatures simultaneously spiked demand for heating energy and froze up about 22 percent of the generators available, leading to emergency conditions. They’re also an attempt to deliver more efficient allocation of resources, potentially adding up to billions of dollars, according to PJM’s analysis.
But environmental and clean energy groups have argued from the start that PJM’s new market structure will make it harder for demand response, wind and solar resources to recognize their value against always-on resources like natural-gas-fired power plants.
That’s mainly because capacity performance doesn’t actually split the market into winter and summer blocks, in a way that would allow programs and technologies that do best in hot weather, such as air conditioning cycling or rooftop solar PV, to bid separately from winter resources, when cold temperatures and heating needs drive peak loads.
Instead, it requires participants to virtually aggregate summer resources with corresponding amounts of winter-focused resources, through a complicated process that we’ve covered in some detail at GTM Squared. The problem is, there aren’t enough remote-control water heaters, thermal energy storage systems, or other forms of winter-focused capacity to match up with the well-established summer-peaking capacity resources.
The results from PJM’s Base Residual Auction last month appear to have borne out the green energy and demand response industries’ concerns. Capacity for the 2020-2021 period cleared a price of $76.53 per megawatt-day, well below the prices of $80 to $100 from last year’s auction. This fact could be taken as a sign that PJM’s new rules are working, by delivering cheaper capacity for its utilities and consumers.
But the auction also revealed a big drop in demand response, down 24 percent compared to last year, and in solar, down more than 60 percent from the year before, Jennifer Chen, attorney for the Natural Resources Defense Council (NRDC), noted in a Tuesday blog post. “As predicted, many summer resources seeking complementary winter resources did not find any to pair with,” she wrote.
PJM did loosen its rules on aggregation for the auction, which helped somewhat. Still, the number of seasonal resources that could combine into annual capacity added up to less than 400 megawatts, or two-tenths of a percent of total procurement, Chen wrote.
PJM’s final implementation of its capacity performance rules has upset more than environmentalists. The groups challenging FERC’s decision in court include NRDC, the Sierra Club, the Union of Concerned Scientists, and the Advanced Energy Management Alliance representing the demand response industry. But it also includes separate complaints from the American Public Power Association and National Rural Electric Cooperative Association, both representing utilities, which argue that the year-round requirements will increase capacity costs, with unclear future benefits.
Even so, the three judges ruled unanimously to uphold FERC’s decision to allow PJM to move ahead with the particulars of its implementation of capacity performance, including the year-round requirement. Chen wrote that NRDC was “reviewing the decision and our options for undoing these costly market rules,” including new complaints filed with FERC, seeking a re-examination of the seasonal capacity issue — an issue that’s unlikely to rise to attention anytime soon, given FERC’s current lack of a quorum.
Measured against these kinds of figures, PJM’s recent work on integrating state carbon policies into its markets may not offer much of an upside to clean energy advocates. Last week, PJM published three white papers laying out its approach to the process, part of a broader effort being driven by FERC to examine the way state renewable and carbon policies affect the operation of interstate energy markets, as we’ve covered at GTM Squared.
The first white paper looks at how PJM could establish a regional or sub-regional carbon price to reflect state renewable and climate change mitigation policies in wholesale market prices. The second looks at a new approach to how subsidized resources like wind and solar power are treated as capacity, by expanding the minimum offer price rule, or MOPR, to these resources.
Finally, the third white paper “does not respond per se to state subsidy programs,” but instead “examines whether the aforementioned profound changes to the industry require re-examination of PJM rules that define when and under what circumstances a generator is eligible to set marginal prices.” There’s a lot more to unpack on the concept in the white paper, but its underlying goal is to deal with “an unintended bias in the energy markets favoring lower-capital-cost resources.” That means things that are cheaper than big power plants, but that may fail to “signal the true, full cost incurred to meet the marginal increment of load.”