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November 17, 2017 Articles

Where to Regulate Electricity? Energy Secretary Rick Perry’s Proposed Rulemaking

The FERC attempts to avoid "blowing the market up."

By Jeff D. Makholm, Ph.D – November 17, 2017

In a letter to the Federal Energy Regulatory Commission (FERC) on September 28, 2017, U.S. Energy Secretary Rick Perry called on that agency to consider a proposal that would essentially return to cost-of-service regulation coal and nuclear power plants that serve regions with wholesale power markets. From the day that Perry sent his letter to the FERC, the industry has been abuzz. Former FERC chair Jon Wellinghoff said that it would “blow the market up”—a phrase that has stuck with Neil Chatterjee, the current FERC chair, who pledged to avoid such a result however the FERC deals with the proposed rule.

In short, the proposed rule permits traditional regulated cost-of-service recovery for “certain eligible” power plants located in regions with FERC-approved wholesale power markets. Eligibility depends on having a “90-day fuel supply on site in the event of supply disruptions caused by emergencies, extreme weather, or natural or man-made disasters.” See Letter to the FERC from Secretary Perry, Sept. 28, 2017, p. 7. The 90-day on-site rule effectively applies only to coal and nuclear plants—gas plants, served by pipeline from distant underground gas fields, cannot qualify.

By the time this short note appears, the FERC will be deep into its work on the subject (perusing 300 written comments from industry, interest groups, and others). It would be easy to frame the proposed rule as simple protectionism for the coal and nuclear industries in a power-supply sector increasingly dominated by modern gas-fired plants drawing from a technologically advanced and highly competitive U.S. gas market. But there is more to the issue than protectionism. Competitive wholesale power markets in the United States have persistent problems squaring competitive principles with industrial and financial realities. These problems lie at the heart of what ails wholesale power markets in the United States—where power and gas markets intersect.

Secretary Perry invoked both the polar vortex and recent hurricanes as justifications for the proposed rule. See Letter to the FERC from Secretary Perry, Sept. 28, 2017, p. 1. Cold winter weather and hurricanes are two different sorts of problems for energy markets generally. Both highlight persistent shortcomings in wholesale power markets.

The Struggles Between Gas and Electricity Markets
The proposed rule has its origin in the “cold weather event” of February 2011 when the worst winter storm in 50 years hit the southwestern region on the United States. During that event, 210 individual generating units in the Electric Reliability Council of Texas, Inc. (ERCOT) had an outage or a failure to start. Combined with other events with generators in Arizona and New Mexico, about 4.4 million electric customers suffered controlled blackouts. See Federal Energy Regulatory Commission and North American Electric Reliability Corp., Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1–5, 2011, August 2011, 140–41.

The result of the “cold weather event” was a broad-based analysis of the intersection of gas and electricity markets. In 2013, Ernest J. Moniz, then the director of the MIT Energy Initiative (just before his appointment as Perry’s predecessor as secretary of energy) hosted a symposium entitled Growing Concerns, Possible Solutions: the Interdependency of Natural Gas and Electricity Systems dealing with the perceived interdependency problems between those two markets. That symposium, and other work, led to FERC action in 2015 synchronizing the timing of the electricity and gas planning days and other scheduling practices.

But better daily scheduling was only a somewhat minor and obvious problem. Bigger problems loomed.

The Polar Vortex: Extreme Weather and Expensive Electricity
The “polar vortex” blew up the New England power market in early 2014, so to speak. With very cold winters, no indigenous fossil fuels, the fastest-growing fleet of combined-cycle (CCGT) gas fired plants, “end of the line” for distant gas supply, and an import point for liquefied natural gas (LNG), it was the very place where fuel and power markets could be expected to clash.

Here is the problem: The interstate pipeline capacity infrastructure, upon which the growing CCGT fleet depends, was built to serve the peak needs of gas customers. Thus, the competitive CCGTs had a difficult time obtaining “sublet” (i.e., “released”) capacity when the polar vortex hit. Figure 1 shows how Boston electricity and delivered gas prices spiked.

Figure 1: The Polar Vortex: Electricity and Delivered Gas Prices, 2012–2015

See Hitchens, N. & Maguire, G., "Generators’ Appetite to Finance Pipeline Capacity: New England and South Australia," The Electricity Journal, Vol. 28, Issue 10 (Dec. 2015), p. 100.

Those price spikes aroused strong local public opinion. In response, governors in five New England states asked their electricity distributors, directed by their state regulatory commissions, to devise a plan to reserve their own firm interstate gas pipeline capacity in amounts that would pay off in lower electricity prices (as the electric companies would release that capacity to power generators). See FERC Docket No. EL16-93-000, Protest and Answer of Eversource Energy Service Co., July 28, 2016. That initiative failed in the courts—challenged successfully by anti-pipeline interest groups and the LNG importer (for whom the price spikes meant higher earnings) on the grounds that the electric restructuring legislation prohibited electric utilities from intervening in power markets. See Engie Gas & LNG LLC vs. Dep’t of Pub. Utils., (56 N.E. 3d 740) (Mass. 2016). The challenge rested on the legislative direction that Massachusetts electricity distributors were not authorized to participate in unbundled electricity markets—an “institutional” barrier. At the same time, generators had also complained to the FERC that the governors’ actions amounted to an attempt to manipulate wholesale power prices (which, in a sense, was quite true). See FERC Docket No. CP15-523-000.

The tension between electricity and gas markets in New England remains. See "ISO New England’s van Welie warns energy crunch, green push could lead to blackouts," SNL Energy (Oct. 10, 2016); see also Van Welie’s testimony before the House Subcommittee on Energy on July 26, 2017. More pipeline capacity to New England could lower power prices. But there is no party to pay pipeline companies to fund the investment requires.

Hurricanes: Gas Supply Reliability
Secretary Perry mentioned the recent 2017 Hurricanes Harvey, Irma, and Maria in his letter. As hurricanes go, they were highly destructive. But they did not match the way in which the 2005 Hurricanes Katrina and Rita tested the reliability of the gas-supply system. Those back-to-back hurricanes shut down the Henry Hub for a day and a week, respectively, when that facility (the central point of the North American gas trade) was physically underwater. See Energy Information Agency, Natural Gas Weekly Update (Sept. 29, 2005).

And yet the competitive gas and pipeline capacity markets, created through FERC action throughout the previous decades, performed reliably. In 2010, I documented the response to Katrina and Rita; charting the range and average of the 84 “basis differentials” relative to the price at the Henry Hub in Louisiana, between April 2005 and April 2006. See Makholm, J.D., "Seeking Competition and Supply Security in Natural Gas: The US Experience and the European Challenge," Lévêque, F., Glachant, J-M., et al., (eds.), Security of Energy Supply in Europe, Edward Elgar, Cheltenham, UK (2010), pp. 21–55.

Figure 2: The Hurricane Season of 2005-2006

After those two natural disasters, the gas markets in each of the 84 nationwide regions cleared without physical shortages, with prices adjusting to equate regional supply and demand—prices that returned to baseline reasonably quickly. The gas market worked reliably throughout the period, proving its resilience even in the face of such successive natural disasters.

There is bound to be heavy emphasis on the physical supply security of the U.S. interstate gas system in the analysis of Secretary Perry’s proposed rule. But given the responsiveness of the deregulated gas market to even major physical disruption, such as the Katrina and Rita one-two punch, it will be hard to make an objective case for re-regulating a sizeable share of the power-generation fleet based on the physical reliability of the gas network.

Where Regulation Continues to Focus on Reliability
As cold weather and natural disasters show, reliable energy supply depends on infrastructure built to deal with highly unlikely events. Gas and electricity markets deal with the problem differently—with useful results for gas markets and controversy for wholesale power markets (and Secretary Perry’s letter).

The pipeline infrastructure that makes the competitive U.S. gas market possible depends on the secure buying power of millions of gas consumers, working through their local gas-distribution businesses and only as permitted by state regulators, to fund a reliable interstate pipeline system that, among other things, is the only source of winter heating for 60 million U.S. households. Even today, major new pipelines need such long-term assurances to obtain financing for their great cost. As a typical example, in the Algonquin Incremental Expansion Project into New England, the entire 342,000 dekatherm-per-day capacity expansion was subscribed by 10 investor-owned or municipal gas-distribution utilities. See Federal Energy Regulatory Commission, Algonquin Incremental Expansion Project, Final Environmental Impact Statement, Docket No. CP14-96-000, Volume 1, pp. 1–3.

It is a veritable “modern miracle” that the regulated and competitive parts of the gas industry exist so well side-by-side. See, e.g., Makholm, J.D., "Electricity Deregulation Under Siege, Take 2: The Temptation of the Kleptocrats," Natural Gas and Electricity, (Dec. 2017.) The miracle owes partly to the straightforward nature of the gas-supply business (where the fuel travels at the speed of a galloping horse—not electricity’s speed of light) and partly to an industry that cleanly split decades ago into its interstate and local components—with their own respective regulators that have long stayed out of each other’s way.

There is no such modern miracle associated with competitive wholesale power markets. True, the industry has the North American Reliability Council (NERC), created in the wake of the infamous Northeast Blackout of 1965. But NERC authority in planning changed with the advent of wholesale markets and the restructuring of local electric utilities. With today’s wholesale power markets, there is no clean separation of interstate/local regulatory responsibility (other than Texas, which avoids FERC regulation in its intrastate ERCOT region). Only two wholesale power markets enjoy only having to deal with overlapping set of federal/state regulators (i.e., New York and California). The others have the extra governance challenges that come with dealing with multi-state independent system operators (ISOs), local state regulators, and the FERC all at once.

In this difficult regulatory/competitive context, it is not possible to duplicate the harmonious coexistence of public-interest planning and complementary competitive markets that the gas industry enjoys. For an economy that already depends so widely on its energy markets, however, the best result of the FERC’s investigation into Secretary Perry’s proposed rule would press for more consistent and workable competition, not more cost-of-service regulation. In the case of polar vortexes in New England, it would mean clearing the administrative pathways to extending new, highly reliable pipeline capacity where electricity consumers would enjoy lower power costs. Nuclear power, for its part, may always require particular emphasis outside the U.S. pool-based pricing mechanisms. See "Illinois and New York Rescue Nuclear Plants; Other States May Follow," Institute for Energy Research (May 9, 2017). However the disparate elements of regional power markets come together, the best path would generally mean expending more energy to tackle the economic and administrative problems impeding a power market that captures the costs of a diverse and reliable competitive generating fleet and less on protectionism and re-regulation—despite the wholesale power markets’ growing pains.


Jeff D. Makholm, Ph.D, is with NERA Economic Consulting in Boston, Massachusetts.

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