APPA questions the benefits attributed to organized power markets.
Elise Caplan is the manager of the Electric Market Reform Initiative (EMRI) for the American Public Power Association. Previously she was an economic and legislative consultant for the Connecticut Municipal Electric Energy Cooperative (CMEEC), and before that was research director for the Illinois Citizens Utility Board.
Recently Public Utilities Fortnightly published an interview with William Hogan, Raymond Plank Professor of Energy Policy at the John F. Kennedy School of Government and “chief architect of wholesale electric market design in the United States,” according to the introduction to the interview (see “Bill Hogan, Unbundled”).1 In this interview, Hogan provides his assessment of the benefits of the restructured wholesale electricity markets operated by regional transmission organizations (RTO). As noted in Fortnightly, the American Public Power Association (APPA), through its Electric Market Reform Initiative (EMRI), has conducted numerous investigations of the RTO-operated markets and developed detailed proposals for reforming these markets. The conclusions reached by these EMRI studies and the recommended reforms have been in sharp contrast to Hogan’s positive assessment of the markets. APPA therefore is responding herein to Hogan’s statements and providing public power’s perspective on the success or lack thereof of the restructuring of the wholesale electricity markets.
Electric Market Reform
In 2004, APPA’s public power utility members began to report concerns about the wholesale electricity markets operated by RTOs. Difficulties with these markets included higher than expected prices for power supply and transmission services; the virtual inability to enter into long-term contracts at prices other than those reflecting the high clearing prices available in the spot markets; the significant lack of needed investment in new generation and transmission facilities; problems with market monitoring, governance, and accountability; and the high RTO administrative and operational costs, as well as the high transaction costs of dealing with the RTOs. Such concerns led to the formation of EMRI in 2006 with the stated goals of undertaking a series of investigative studies of the RTO-operated markets and, if necessary, using the findings of these studies to develop a proposal for market reforms.
In the six years since EMRI began, criticisms of these markets have continued, despite significant drops in electricity prices. More recent concerns have centered on the RTO-operated capacity markets and recent rule changes that seek to block the entry of new, more efficient generation. A review of presentations to financial analysts by the largest merchant generation owners with existing depreciated generation units demonstrates a strong relationship between these two developments: as prices fall, merchant generators must look to the capacity markets to make up the revenue and protect their profits. As a result, there have been successful efforts to constrain supply and block new entry, raising significant questions not only about the future costs to consumers but about the ability of the RTO regions to address the impending challenges of retiring coal plants, integrating variable energy resources, and managing the complex interrelationship of the electricity and natural gas markets.
The findings of the EMRI studies raise significant questions about whether wholesale market restructuring has met its intended goal of supporting competition that produces efficiencies and reduces costs to consumers. Two key findings of the studies support this conclusion. First, the price disparity between restructured and traditionally regulated regions of the country has increased since restructuring started. Second, merchant generators historically have generally earned higher profits than their regulated counterparts, although those earnings have been trending downward this past year. Under a truly competitive and non-discriminatory market, higher prices and profits would invite entry and such entry would in turn lower prices, reducing the profits of merchant generators with existing units.
In 2009, APPA developed a plan to reform the RTO-operated wholesale electricity markets, called the Competitive Market Plan, which APPA updated in 2011. In developing its plan, APPA recognized that it wouldn’t be feasible to dismantle the existing RTOs, and recommended that core beneficial RTO operations be maintained, including centralized least-cost dispatch, transmission planning, and ensuring open access. The plan focused instead on the RTO-operated markets, with the goal of significantly increasing the use of bilateral contracting for the procurement of energy and capacity. Under this vision of the wholesale electricity markets, the RTO energy and ancillary service markets would be true residual markets, used primarily to balance electricity supply and demand, rather than as the primary market for procurement of energy. The APPA plan recommended a phase-out of the RTO-operated capacity markets, and encouraged states—alone or in concert—to implement competitive procurement programs to obtain both supply and demand-side resources through a series of bilateral contracts of varying terms. The plan called for dialogue among all stakeholders and concluded that:
“The debate should no longer be about who can best massage the statistics or whether it is more virtuous to support ‘competition’ or ‘regulation.’ Instead, the industry must work together to develop a regulatory regime for electricity markets in RTO regions that will truly benefit consumers, businesses and the environment. Unless the electric utility industry and all of its regulators, retail and wholesale, can agree on a market design and regulatory paradigm that fairly balances the interests of both load and generation, the industry will be condemned to continued upheaval.”
Following the 2009 release of the APPA plan, Hogan co-authored with John Chandley of LECG a paper titled, Electricity Market Reform: APPA’s Journey Down the Wrong Path. (Although not acknowledged in the paper itself, Dr. Hogan’s website refers to it as a “Compete Coalition Paper.”) In this paper, the authors went to great lengths to discredit and mischaracterize APPA’s plan. The authors asserted that “it is not an exaggeration … to describe [APPA’s proposed] approach as akin to detailed less-than-cost-of-service regulation.” While claiming that generators wouldn’t earn sufficient funds to cover their costs, Hogan also concluded that APPA’s proposal would “cost consumers billions of dollars.” In fact APPA’s plan acknowledges the needs of the generators to earn sufficient revenue, but recommends that the bulk of such revenue be earned through bilateral contracts, rather than RTO markets. Such contracts would be negotiated through competitive procurement processes. Moreover, APPA included no set restrictions on the use of the residual energy and ancillary services markets in the plan.
The continuing debate over the successes, failures, and need to reform the RTO-operated markets is revived in “Bill Hogan, Unbundled.” In this interview, Hogan selects a few pieces of evidence he purports to demonstrate the success of wholesale electricity market restructuring. However, such claims, when unbundled, don’t hold up to scrutiny.
Unbundling Dr. Hogan’s Statements
First, Hogan cites the often-referenced increase in nuclear power plant capacity factors following deregulation, stating that the “capacity factor climbed from the low 60s to the 90s.” In reality, according to a Compete Coalition-sponsored Navigant study, capacity factors for nuclear power plants in RTO regions increased from 81 to 93 percent between 1996 and 2007. The Navigant study, however, didn’t provide a comparison to non-RTO nuclear power plants. A 2007 APPA analysis found that capacity factors increased nationwide during this period. Moreover, individual plants that were sold to unregulated generators followed very different patterns. For example, between 1995 and 2005, the Oyster Creek and Vermont Yankee plants saw overall decreases in their capacity factors following their sale to an unregulated owner. Three Mile Island and Pilgrim reached their greatest capacity factor over the 10-year period in the years before they were sold to deregulated firms. And the dispute over the likely inadequacy of decommissioning funding for Vermont Yankee exposes the seamy underside of ostensibly competitive deregulated nuclear units; will their owners set aside the substantial dollars needed to decommission them, or attempt to stick consumers with the eventual bill?
The second example of deregulation’s success Hogan cites is the “famous graphic when AEP joined PJM, and what happened to their inter-regional trading.” This graphic is hardly a conclusive finding of a benefit. It simply shows a dramatic increase in export of power from the Midwest to the East as AEP gained access to dispatch of power across PJM in October 2004. While this might be an example of the outcome of centralized dispatch across a wider geographic area, it doesn’t mean there were net benefits to consumers. Simply because AEP, a vertically integrated utility, could sell a greater amount of power into the East, doesn’t demonstrate that such actions were beneficial to the region as a whole. In fact, between 2004 and 2005, average prices in PJM increased by about 40 percent in both the real-time and day-ahead markets as a result of the dramatic increase in natural gas prices resulting from hurricane Katrina, and appear to have been unaffected by the increase in power sales across the region.
The third benefit Hogan cites is the often-repeated argument that under the old days of regulation, utilities recovered their costs of everything that they built, putting customers at risk. Under deregulation, the argument continues, shareholders bear the risk if a plant isn’t financially viable. But in fact, merchant generation owners have successfully ensured that the RTO market rules are continually revised to minimize their risk and maintain their high earnings—at a significant cost to consumers. It’s certainly more profitable for incumbent generators to increase prices and collect profits on existing depreciated generation assets by placing impediments to new supply and building little or no new generation. But such actions are unlikely to be in the best interest of consumers.
What Missing Money?
Hogan frequently refers to the problem of the generators’ “missing money,” or the gap between costs and earnings. For example, in the interview Hogan states: “The prices in the energy markets are too low even though people are always complaining about prices being too high. You can go through the analysis, and see that they’re too low. This is the ‘missing money’ problem, as it’s called.” Fundamentally, there is a logical inconsistency between claiming that the markets place risks on shareholders and not consumers, as would be the case under true competition, while at the same time seeking revenue sufficiency, often a feature of regulation. Mixing the two provides the worst of both the competitive and regulatory worlds for consumer and businesses while providing the best of both for incumbent generation owners.
There’s no measure of the degree to which there is “excess” or “missing” money in the markets. APPA has long supported an RTO performance metric that would compare a comprehensive measure of all revenue earned by merchant generators with their actual fixed and operating costs to determine their actual excess earnings. But such a metric was rejected by FERC in its proceeding to develop RTO performance metrics.
Because many of the merchant generators are owned by public companies, their 10-K forms provide data that can be used to paint a picture of this excess money. APPA has analyzed the profits earned by merchant generators, as measured by their returns on equity, and found that these profits have consistently exceeded the earnings of regulated utilities. The degree to which there’s a divergence between actual costs and revenues is necessary to determine the benefits of moving from cost-of-service regulation—where utilities are allowed to recover prudently incurred costs through rates—to a deregulated market. Such data belie the assertion that the generators assume the risks in a restructured market.
Capacity Market Benefits?
Hogan and other market observers don’t differentiate between the revenue and cost considerations facing new independent entrants and owners of older incumbent generation in RTO markets. In fact, many of the new entrants strongly favor the steady stream of revenue offered by a long-term contract over uncertain short-term revenue streams produced by the markets. Owners of incumbent generation units generally prefer the volatile markets where they can earn revenues far in excess of the low fixed costs associated with their older, depreciated units. In recent years, energy prices have declined sharply, which has raised the importance of the capacity markets as a stream of revenue for the incumbent generators. As a result, many of the incumbent generators have sought and achieved changes to what is known as the Minimum Offer Price Rule (MOPR) that pose impediments to new entry—all under the guise of mitigating buyer-side market power. This rule seeks to replace the actual costs of a new generator with an administratively imposed price floor for offers to sell resources into the capacity market auctions. These barriers to entry raise significant doubts about the competitiveness of RTO markets.
Although capacity markets have caused some of the most problematic aspects of the electricity markets, Hogan notes that he didn’t include capacity markets in the model “because they’re not part of the design.” But these capacity markets have in fact developed in many of the RTOs, and therefore can’t be simply assumed away as inconsistent with Hogan’s vision. The development of the capacity markets and their subsequent rule changes is a direct result of several key features of the markets that exist outside of pure theoretical economics, primarily the nature of the governance and the outsized influence of incumbent merchant generators in the development of new market constructs.
While not explicitly supporting capacity markets, Hogan strongly supports market constructs within these markets that would provide an anti-competitive advantage for these older units. For example, Hogan has advocated in ISO New England, PJM, and the New York ISO for a two-tiered pricing system where older, existing generators receive a higher price for their capacity than the price paid to new entrants. It’s difficult to see how this concept meshes with the goals of competition, non-discrimination, and open access.
Despite supporting these barriers to new supply, Hogan states in the interview: “The truth of the matter is that the real benefits are going to be measured in long-term investment profiles.” APPA completely agrees. Using these criteria, the data on new investment don’t support a finding of benefits from the RTO markets. A recent APPA study found that 98 percent of the new capacity constructed in 2011 was built under utility or customer ownership, and not for sales into RTO markets.
Competition and Enforcement
With regards to the energy markets, APPA has long been concerned about the role of financial entities participating in the markets not to serve end use customers but solely to profit from buying and selling energy and related products. Over the past year, FERC has opened a number of investigations into the trading activities of financial entities, finding evidence of market manipulation in several cases. Hogan sharply criticizes FERC’s increased enforcement efforts, asserting: “I think the people in the enforcement office don’t know what they’re doing, and, in many ways don’t care. So, for example, I believe they think that if they had a strong enforcement case even though it would completely cripple the operation of competitive markets, that would be OK.”
One can argue, however, that the facts of these cases demonstrate not the operation of competitive markets, but the ability of financial entities to take advantage of complex rules and structures. For example, it’s alleged that JP Morgan exploited provisions for “make-whole” payments in the California and Midwest markets. JP Morgan Ventures Energy Corp. allegedly submitted negative offers in the day-ahead market and very high offers in the real-time market, ensuring that the generators wouldn’t be dispatched in real-time but instead would receive make-whole payments for their minimum operating costs. What was intended as a rule to protect generators from losses in the event they were dispatched in the day-ahead but not the real-time market might have been misused to ensure profits, at the expense of consumers. To argue that these entities are merely providing liquidity to markets and market participants through their activities could prove naïve at best and cynical at worst. FERC staff should be allowed to investigate these activities, and judgment should be withheld until all the facts are known.
[Editor’s Note: After publishing “Bill Hogan, Unbundled,” Fortnightly learned that Hogan provided testimony supporting Deutsche Bank in its defense against FERC enforcement action. Fortnightly’s Bruce Radford analyzed that case in his December 2012 article, “Trading on a Knife Edge.”–MTB]
Calling for Dialogue—Again
APPA continues to call for constructive dialogue on how best to reform the markets to achieve the greatest benefits for both consumers and suppliers. The complexities of the RTO markets, coupled with the challenges facing the nation in meeting its electricity needs at a reasonable cost, call for market reforms. We all must move past economic theory and idealized market designs to deal with the real financial incentives facing incumbent merchant generators, new suppliers, and other players, as well as the actual financial commitments required to anchor needed new infrastructure, the appropriate role of financial entities in the markets, and finally, the politics of RTO governance and decision-making. Glossing over such realities and hiding behind economic theory does a disservice to consumers and the economy as a whole.
1. John Bewick, “Bill Hogan, Unbundled,” Public Utilities Fortnightly, November 2012, p.10.
2. Price Signals and Greenhouse Gas Reduction in the Electricity Sector, Prepared for the Compete Coalition by Navigant Consulting, 2009.
3. Nuclear Plant Performance: What Does Restructuring Have To Do With It?, American Public Power Association, May 2007.
4. Financial Performance of Owners of Unregulated Generation in PJM: 2011 Update, American Public Power Association, June 2012.
5. Initial Statement of William W. Hogan, FERC Technical Conference, July 28, 2011, Docket Nos. EL11-20-001 and ER11-2875-001 -002.
6. Power Plants Are not Built on Spec, American Public Power Association, March 2012, 8